UNIVERSITY OF LJUBLJANA

FACULTY OF ECONOMICS

MASTER'S THESIS

AN ANALYSIS OF THE TURKISH ELECTRICITY MARKET

Ljubljana, September 2015 TANJA MIMOVIĆ

AUTHORSHIP STATEMENT

I, the undersigned Tanja Mimović, a student at the University of Ljubljana, Faculty of

Economics, (hereafter: the FELU), hereby declare that I am the author of the master’s thesis

entitled “An Analysis of the Turkish Electricity Market”, written under the supervision of

Professor doc. dr. Matej Švigelj.

In accordance with the Copyright and Related Rights Act (Official Gazette of the Republic of

Slovenia, No. 21/1995 with changes and amendments), I hereby allow the text of my master’s

thesis to be published on the FELU’s website.

I further declare that:

the text of my master’s thesis is based on the results of my own research;

the text of my master’s thesis is language-edited and technically compliant with the

FELU’s Technical Guidelines for Written Works, meaning that I

o cited and/or quoted the works and opinions of other authors in my master’s thesis

in accordance with the FELU’s Technical Guidelines for Written Works, and

o obtained (and referred to in my master’s thesis) all the necessary consents to use

the works of other authors that are entirely (in written or graphical form) used in

my text;

I am aware of the fact that plagiarism (in written or graphical form) is a criminal offence

and may be prosecuted in accordance with the Criminal Code (Official Gazette of the

Republic of Slovenia, No. 55/2008 with changes and amendments); and

I am aware of the consequences a proven charge of plagiarism based on the submitted

master’s thesis could have for my status at the FELU in accordance with the relevant

FELU Rules on Master’s Thesis.

Ljubljana, 25 September 2015 Author’s signature:

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TABLE OF CONTENTS

INTRODUCTION

………………………………………………………….….….….....……..1

1 EUROPEAN UNION ELECTRICITY MARKET ………………………..….……….…….3

1.1 Establishment of a European Union internal electricity market …….….….………….…..4

1.2 Regional electricity markets in the European Union

…………….………..………...........10

1.2.1 Electricity Regional Initiative

………………………………………...………............10

1.2.2 South East Europe ………………………………………………….….………….….13

1.3 Turkish electricity market overview and its interconnection with the SEE region

…..…...……………………………………………………………………………………15

2 ELECTRICITY MARKET REFORM IN TURKEY

……………….…….……….…….…17

2.1 Turkish electricity market prior to reform

………………………….….…………..……..17

2.2 Institutional framework ……………………………………………….………...….….…19

2.2.1 Electricity Market Law No. 4628

……………………………….…………….……...19

2.2.2 New Electricity Market Law No. 6446

….…………...…….……………….....……...22

2.3 Privatization

……………………………….……………………….…………...…..…….23

2.3.1 Privatization of distribution companies

……………..……….…………......….….…..23

2.3.2 Privatization of generation assets

……………………………………………….….....25

3 TURKISH ELECTRICITY MARKET ANALYSIS ……………………………...….……27

3.1 Generation …………………………………………………………………………….….27

3.1.1 Natural gas ………………………….…………………………………………….…..29

3.1.2 Coal

…….……………………………………………………………………….….…33

3.1.3 Hydroelectric power ….…………………………………………………...……….…34

3.1.4 Renewables ..…………………………………………………………..……….……..35

3.2 Transmission…….………………………………………………....………….…….……37

3.3 Wholesale market…………………………………………………….…………….……..40

3.3.1 Bilateral contracts and the role of TETAS ……………………...……………………41

3.3.2 Derivatives

…….…………………………………………,…………………………..45

3.3.3 Day-ahead market

……….……………………………….…………………………...45

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3.3.4 Balancing market ………..…………………………………………………….……...47

3.3.5 Price determination and market data ……………………………………….….……..47

3.3.6 Expected future market developments ………………………………….........………50

3.4 Distribution and retail market….…………………………………………………………51

4 ASSESSMENT OF ELECTRICITY MARKET DEVELOPMENTS IN TURKEY ………

56

4.1 Level of harmonization of Turkey’s electricity market with EU legislation and

practices…………………………………………………………….………………………...56

4.2 Future challenges……….. ……………………………………………………………….58

CONCLUSION ………………………………………………………………………………61

REFERENCE LIST ………………………………………………………………………….63

LIST OF FIGURES

Figure 1. Electricity supply chain – competitive and regulated activities ............................................... 5

Figure 2. Population of Turkey and GDP growth rates for Turkey, the Euro Area and OECD countries

............................................................................................................................................................... 15

Figure 3. Turkish electricity demand 1975-2013 .................................................................................. 16

Figure 4: Unbundling of public assets ................................................................................................... 19

Figure 5. Proportion of Turkey’s total installed capacity accounted for by EUAS 2006-2013 ............ 27

Figure 6. Electricity generation in Turkey by primary resources, 2013 in percentages ........................ 29

Figure 7. Turkish natural gas market structure ...................................................................................... 30

Figure 8. Lignite and hard coal rich regions in Turkey ........................................................................ 34

Figure 9. Production, consumption and import of coal in Turkey, 2005-2012 ..................................... 34

Figure 10. Turkey’s installed renewable capacity and thermal capacity 2006-2013 ............................ 38

Figure 11. Turkey’s interconnection with neighbouring countries ....................................................... 38

Figure 12. Total electricity imports and exports by Turkey 2003-2013 ................................................ 40

Figure 13. Current structure of the wholesale electricity market .......................................................... 41

Figure 14. Bilateral contracts electricity market and energy flow ........................................................ 43

Figure 15. Market share of TETAS 2002-2013, in percentages ............................................................ 44

Figure 16. Proportion of the Turkish wholesale electricity market accounted for by bilateral contracts,

and bilateral contracts by sector (on 9 October 2014), in percentages .................................................. 45

Figure 17. Private and bilateral contracts .............................................................................................. 45

Figure 18. Volume and value of base load electricity futures (2011–2013) ......................................... 46

Figure 19. Price determination on the day-ahead market (left) and balancing market (right) .............. 49

Figure 20. Turkish wholesale electricity market price .......................................................................... 50

Figure 21. Wholesale electricity market prices of the EU REM (Q2 2013).......................................... 51

Figure 22. Retail market opening in Turkey ........................................................................................ 53

Figure 23. Retail prices for household customers in Turkey and EU countries (2013) ........................ 56

Figure 24. Retail prices for industrial customers in Turkey and EU countries (2013) .......................... 56

Figure 25. Retail prices for industrial and household customers in Turkey (2010–2014) .................... 57

Figure 26. Distribution losses (loss and theft ratios), 2013 in percentages ........................................... 60

Figure 27. Share of natural gas in electricity generation ....................................................................... 62

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LIST OF TABLES

Table 1. Electricity Regional Initiative (ERI) .......................................................................... 10

Table 2. 2014 SEE region status (integration with the EU’s IEM) .......................................... 14

Table 3. Electricity distribution regions in Turkey, distribution companies and the

privatization thereof ................................................................................................................. 23

Table 4. Privatization of major thermal power plants 2013-2014 ............................................ 26

Table 5. Distribution of installed capacity by primary energy resources and market share of

electric utilities in Turkey, 2013 .............................................................................................. 28

Table 6. Natural gas and LNG sale and purchase agreements (BOTAS) ................................ 30

Table 7. Natural gas prices for Turkey 2012–2013 (for BOTAS) ........................................... 31

Table 8. TETAS trading portfolio in 2013 (purchase) ............................................................. 44

Table 9. Generation company X’s portfolio ............................................................................. 47

Table 10. Example of flexible sales/bids of generation company X ........................................ 48

Table 11. Comparison of the current and new wholesale electricity market structure ............ 52

Table 12. Harmonization with EU legislation and practices .................................................... 59

Table 13. System losses by SEE contracting parties, 2013 in percentages .............................. 61

1

INTRODUCTION

The 20th

century saw a rapid increase in population as well as industrialization. This resulted

in a huge demand for energy across the world (Baris & Kucukali, 2012, p. 377). Global total

net electricity generation reached 17,331 terawatt hours (TWh) in 2005 and is projected to

increase to 39,034 TWh in 2040 at a growth rate of 2.2% (2010–2040), as reported in an

International Energy Outlook 2013 reference case (U.S. Energy Information Administration,

2013). In the same reference case, global energy consumption (liquids, natural gas, coal,

nuclear and other) is projected to grow at a rate of 1.5% in the period 2010–2040.

Data regarding the Turkish electricity market is comparable to the upward global electricity

generation trend. Electricity generation in Turkey totalled 162 TWh in 2005 compared with

240 TWh in 2013. This is a 50% increase in the period 2005–2013 (TurkStat, 2014). The

country’s electricity demand has historically been high, except in 1999 when Turkey suffered

a devastating earthquake, and in 1994, 2001, 2008 and 2009, years in which the country faced

a severe economic crisis. An increase in electricity demand is expected, from 242,020

gigawatt hours (GWh) in 2010 to 499,490 GWh in 2020, as a consequence of the projected

increase in the population and the country’s economic growth (Atiyas, Çetin, & Gülen, 2012,

p. 15; Baris & Kucukali, 2010, p. 2441).

Electricity plays an important role in every country’s economy, since it represents a crucial

factor to economic and social development (Toklu, 2013, p. 456). The main features of the

electricity market have been economies of scale in generation and the fact that generated

electricity must pass through an extensive transmission and distribution network to be

delivered to the end-customer (Kopsakangas – Savolainen & Svento, 2012, p. 5). Due to these

natural monopolistic characteristics, international electricity sectors were operated by the state

as a natural monopoly (also referred to as a state monopoly) during the 20th

century, resulting

in a situation where a state-owned company dominated the entire electricity supply chain,

including generation, transmission and distribution.

It was later determined, however, that introducing competition to potentially competitive

segments of the industry might increase its overall efficiency. This meant that network

activities such as transmission and distribution (with its natural monopolistic characteristics)

should be segregated from generation, wholesale and retail sales activities (which were

recognized as potentially competitive activities) (Kopsakangas-Savolainen & Svento, 2012, p.

5).

This led to the start of energy market1 reform at the international level. “Since each country

differed in terms of their geography, availability of domestic resources, energy trade balance,

composition of their economy, and socio-political conditions, the restructuring approach

differed” from country to country (Atiyas et al., 2012, p. 1). Nevertheless, reform comprises

four fundamental elements common to all countries: “privatization of publicly owned

electricity assets; the opening of the market to competition; the extension of vertical

1 In literature, the term energy markets usually refers to gas and electricity markets. In this master’s thesis, the

term refers to electricity markets.

2

unbundling of transmission and distribution activities from generation and retail activities;

and the introduction of an independent regulator” (Pollitt, 2009, p. 4).

One of the first countries to reform its electricity sector was Chile (1987). Just two years later,

England and Wales also initiated a massive privatization and restructuring process (1989).

The motivation behind the reform was to make the energy sector cost efficient through the

introduction of competition (Sioshansi, 2006, p. 70). Alongside the economic motivation for

reform, there were also political incentives such as distaste for strong unions and the urge to

attract foreign investment, as well as environment concerns (Woo, Loyd & Tishler, 2003, p.

1104).

With its strategic and political goals, as well as economic concerns, the EU has also been

engaged in a debate on the restructuring of energy markets (Baha Karan & Kazdağli, 2011).

The main idea was to create an internal electricity market with effective competition that

mainly benefits customers (by lowering prices) and companies (by reducing the possibility of

the abuse of market power by dominant companies). These benefits were the underlying

principle for the liberalization of European energy markets (Böckers, Haucap & Heimeshoff,

2013, p. 7).

As an EU candidate country, Turkey also followed the global trend of energy sector

restructuring, with its own triggers for reform. One of the main reasons was the rapid growth

in electricity demand and the government’s inability to meet that demand. Another significant

trigger for reform was foreign influence. Firstly, electricity market reform is one of the

preconditions for EU membership. Secondly, international institutions (IMF, World Bank and

OECD) that have supported Turkey through its economic crises highlighted the need for

energy market reform. Moreover, inefficient state monopolies were problematic in many other

developing countries, as well (Erdogdu, 2006, p. 986).

The purpose of this thesis is to analyse the Turkish electricity market following the major

reform thereof, and to assess its current level of harmonization with EU legislation and

practices.

This thesis has five main objectives. The first is to review the EU internal electricity market

and its regional electricity markets, and to compare the Turkish electricity market with the

countries of the South East Europe (SEE) region. The second objective is to identify all

triggers and the historical background of Turkish electricity market reform. The third

objective is to analyse the Turkish electricity market by separately regulated (transmission

and distribution) and competitive (generation, wholesale and retail sales) activities. The fourth

objective is to assess the level of competition and to analyse possible entry barriers for new

market entrants. The final and most important objective is to assess the level of harmonization

of Turkey with EU’s rules, legislation and practices, and to identify future challenges for the

Turkish electricity market.

This thesis has four main chapters that are further divided into several subchapters. The first

chapter describes the EU internal electricity market and its three energy packages. Regional

3

electricity markets are also presented in order to illustrate the connection between Turkey and

the SEE regional market. At the end of the chapter, an overview of the Turkish electricity

market is presented, as well a comparison of the market to the electricity markets of SEE

countries. The implementation of the three electricity directives in Member States is used as a

benchmark for Turkey in order to explain the current status of Turkey and its target model for

the future.

In order to understand the current market structure, the second chapter covers the process of

electricity market reform in Turkey, beginning with an analysis of the market prior to reform.

Triggers and the institutional framework of reform are presented, as well as the privatization

process. Generation and distribution assets for privatization are presented, together with an

overview of the progress of the privatization process.

The third chapter is the most important, since it analyses the current structure and functioning

of the Turkish electricity market. The first subchapter presents an analysis of electricity

generation, in terms of the resources used for electricity generation, as well as the ownership

of generation assets. The role of government and publicly owned companies is also presented.

The next subchapter explains the transmission system and the links between Turkey and

neighbouring countries. Further on, electricity trading is presented in the subchapter on the

wholesale electricity market, which covers the major market player TETAS, as well as

Turkish wholesale market prices and their comparison with other EU regional market prices.

The connection between the natural gas and electricity markets is explained throughout the

chapter. In the last subchapter, an analysis of distribution and retail activities is presented,

together with a graphical presentation of retail prices.

Recent developments on the Turkish electricity market are assessed in chapter four. First, the

level of harmonization of Turkey’s electricity market with EU legislation and practices is

reviewed, followed by a presentation of future challenges for the country. At the end of the

thesis, the main findings are summed up in the conclusion.

The main research methods applied are the descriptive method, together with inductive and

deductive reasoning, and the comparative method. In addition, extensive literature on the

electricity market and the reform thereof was used in order to better understand the topic. For

a detailed explanation, the following databases were used: Turkish Statistical Institute

(TurkStat), Ministry of Energy and Natural Resources Turkey (MENR), Energy Market

Regulatory Authority (EMRA), U.S. Energy Information Administration (EIA), European

Network of Transmission System Operators for Electricity (ENTSO-E), International Energy

Agency (IEA), EU Commission and Eurostat.

1 EUROPEAN UNION ELECTRICITY MARKET

The European Union (EU) electricity market is part of the EU’s wider energy policy.

Historically, the founding Member States highlighted the need for a common approach to

energy with the Coal and Steel Treaty in 1952 and the Euratom Treaty in 1957. Energy

markets have changed significantly since then, and the need for an efficient common energy

policy has grown with the EU’s increasing energy challenges such as climate change,

4

increasing dependence on imports and higher energy prices (Commission of the European

Communities, 2007). The EU is committed to addressing these challenges, primarily through

the establishment of a real Internal Energy Market (IEM), i.e. the creation of an internal

electricity market and an internal gas market.

European energy policy is currently focused on achieving sustainability (to reduce EU and

global greenhouse emissions), the security of supply (investments in additional generation

and the establishment of an effective internal electricity and gas market) and competitiveness

(stimulation of fair and competitive prices) (Commission of the European Communities,

2007; European Parliament, 2014).

1.1 Establishment of a European Union internal electricity market

Historically, the main features of the electricity industry have been economies of scale in

generation and the fact that generated electricity must pass through an extensive transmission

and distribution network to be delivered to the end-customer (Kopsakangas-Savolainen &

Svento, 2012, p. 5). Due to these natural monopolistic characteristics, international electricity

markets were operated by the state as a natural monopoly (also referred to as a state

monopoly) or by a large monopolistic company during the 20th

century, resulting in a situation

where only one (state-owned) company dominated the entire electricity supply chain.

In practice, this meant that the state regulated the electricity sector by setting prices and

defining technical frameworks. The state was usually the regulator, as well as the owner and

manager of electricity companies. Typical examples are the French company EDF, Great

Britain’s CEGB (Central Electricity Generating Board), ENEL in Italy and Verbund in

Austria (Hrovatin & Zorić, 2011, p. 3).

Nevertheless, there was a growing ideological and political disaffection with these vertically

integrated monopolies. Moreover, successful liberalization processes were carried out in other

network industries, and thus led to initiatives to liberalize the electricity industry worldwide

(Meeus, Purchala & Belmans, 2005, p. 25). The EU was no exception. With its strategic and

political goals, as well as economic concerns, it has been actively engaged in a debate on the

restructuring of energy markets (Karan & Kazdağli, 2011, p. 12).

The EU’s main idea was to create an internal electricity market with effective competition

that mainly benefits customers (by lowering prices) and companies (by reducing the

possibility of the abuse of market power by dominant companies). These benefits were the

underlying principles for the liberalization of European energy markets (Böckers et al., 2013,

p. 7). In terms of introducing competition to the electricity market, the generation, trade

(wholesale) and supply of electricity were seen as potential competitive activities, while

network activities (transmission and distribution) were regarded as activities that require

regulatory control (due to their natural monopolistic characteristics), as shown in Figure 1.

5

Figure 1. Electricity supply chain – competitive and regulated activities

Source: N. Hrovatin & J. Zorić, Reforme elektrogospodarstva v EU in Sloveniji, 2011, p. 4.

In the process of reforming a vertically integrated electricity industry into a competitive

industry, there are some general features that can be observed among countries. As explained

by Jamasb & Pollitt (2005, p. 13), four main steps usually occur:

a. Restructuring: Vertical unbundling of generation, transmission, distribution and retail

sales activities.

b. Competition and markets: Creation of a wholesale market as well as retail competition.

Allowing new entrants into generation and retail supply.

c. Regulation: Establishment of an independent regulator. Provision of third-party network

access. Incentive regulation of transmission and distribution networks.

d. Ownership: Allowing in new private actors, by privatizing existing publicly owned

businesses.

The above noted steps were promoted among EU Member States in the scope of European

reform, which was carried out at two parallel levels. First, were the EU electricity market

directives issued by the European Parliament and Council, which brought the liberalization of

national electricity markets. These were significant contributions to the creation of an internal

electricity market. Second, the European Commission encouraged the expansion of cross-

border transmission links, as well as the improvement of cross-border trading rules with the

aim of promoting efforts to improve interfaces between national markets (Karan & Kazdagli,

2011, p. 13; Jamasb & Pollitt, 2005, p. 17).

The EU’s electricity directives were part of the so-called energy packages introduced in 1996,

2003 and 2009, which included a set of regulations and directives in the area of EU energy

policy, all with the aim of creating an IEM.

6

First Electricity Directive – 1996

The legal framework that provided the initiative for the creation of the EU internal electricity

market was Directive 96/92/EC of the European Parliament and of the Council of 19

December 1996 concerning common rules for the internal market in electricity. The main

objective of the aforementioned directive was the introduction of competition on the

electricity market. It represented a set of common rules for all Member States in the areas of

generation, transmission, distribution and supply of electricity.

According to Directive 96/92/EC (OJ L 027), Member States were required to designate

transmission and distribution system operators (TSOs and DSOs) who are responsible for

operating, maintaining and developing transmission and distribution systems.

In terms of restructuring (vertical unbundling), the first directive focused on unbundling and

the transparency of accounts. This was the first step toward the gradual unbundling of

generation, transmission and distribution activities. The first directive instructed Member

States to ensure that their integrated electricity companies keep separate accounts for their

generation, transmission, distribution and supply activities within their internal accounting

records. The aim of such unbundling was to avoid discrimination, cross-subsidization and the

distortion of competition (Directive 96/92/EC, OJ L 027).

Moreover, Directive 96/92/EC facilitated competition in generation in such way that Member

States are able to choose between a tendering or authorization procedure for the construction

of new generating capacities (Directive 96/92/EC, OJ L 027). An authorization procedure

allows anyone to build a power plant, under the condition that they comply with certain

criteria such as safety of installation, environmental protection and the use of public land. A

tendering procedure allows Member States to maintain centralized planning of the power

system, while allowing them to tender out the construction of new capacities (Pellini, 2014, p.

12).

In order to enter the market and to sell and deliver electricity, new suppliers and producers

needed access to the grid. Consequently, Directive 96/92/EC presented three third-party

access models (Directive 96/92/EC, OJ L 027):

a) Negotiated third-party access (nTPA): Eligible customers and suppliers negotiate a

transmission fee (access to the system). Where eligible customers are connected to the

distribution system, access is the subject of negotiations with the relevant network

operator. To ensure transparency, indicative prices for the use of the network must be

published by the network operator.

b) Regulated third-party access (rTPA): Access rights may be granted on the basis of pre-

determined published tariffs.

c) Single-buyer model: Creation of a mandatory power pool for producers, with one entity

acting as a single buyer in the pool (e.g. a system operator may be a single buyer).

7

The concept of ‘‘eligible customer” was introduced for the first time with Directive 96/92/EC.

An eligible customer is defined as a customer who has the legal capacity to contract volumes

of electricity from any supplier. The aim of the directive was the slow, gradual and partial

opening of Member States’ electricity markets in such way that customers and producers

would be able to negotiate the purchase and sale of electricity freely. The first phase opens the

market for end-customers who consume more than 40 GWh per year. After three years, the

degree of market opening increases with a consumption threshold of 20 GWh, followed by 9

GWh after six years (Directive 96/92/EC, OJ L 02).

Although the first directive initiated changes to the electricity markets of Member States, it

also featured some serious shortcomings. In terms of market concentration, monopolies and

oligopolies were still present. Since the form of unbundling required by the directive was

weak, vertically integrated companies still presented a barrier to competition. Overall, there

was a lack of transparency and technical barriers to accessing the grid. Moreover, trading was

not fully established in all countries and balancing markets were not fully developed, while

some markets were too small or isolated. In order to ensure competitive prices and a real

internal electricity market and to increase the standards of service for customers, the Second

Electricity Directive replaced Directive 96/92/EC (Kovács, 2011).

Second Electricity Directive – 2003

Directive 2003/54/EC concerning common rules for the internal market in electricity and

repealing Directive 96/92/EC enforced the unbundling of TSOs as well as the unbundling of

DSOs, in terms of the legal separation of activities. The separation of the ownership of assets

of the transmission/distribution system operator from the vertically integrated company was

not mandatory. The criterion only referred to the legal status and functional activities of TSOs

and the management of DSOs (Directive 2003/54/EC, OJ L 176).

Directive 2003/54/EC (OJ L 176) also enforced the adoption of an authorization procedure for

all Member States for generation, as the only option. The procedure and related criteria

required publishing, while the results were to be objective and non-discriminatory.

Moreover, retail markets were opened as the result of Directive 2003/54/EC, since all non-

household customers were considered eligible from 1 July 2004, while all customers were

deemed eligible from 1 July 2007 (Meeus et al., 2005, p. 27).

In addition, Directive 2003/54/EC (OJ L 176) instructed Member States to designate a

regulatory authority to be responsible for “ensuring non-discrimination, effective competition,

efficient functioning of the market and monitoring of the market”. The aforementioned

authority is wholly independent from the interests of the electricity industry.

Since the Second Electricity Directive was not specific in terms of how to ease the

monopolistic situation on the market and how to introduce wholesale electricity markets,

several shortcomings remained to be resolved. Although almost all Member States ensured

competition in generation via a transparent authorization procedure, some issues remained

unresolved and the generated electricity was not entirely sold on the market. Access to the

grid was no longer a problem. On the other hand, there was no incentive to enter the market

8

due to the lack of competitive and liquid wholesale markets. In addition, TSOs and DSOs

were required to legally separate the functioning of their network from generation and/or

retail activities. In practice, TSOs or DSOs were still owned by a company involved in

generation or retail activities, which represented a barrier to competition. Moreover, one of

the most serious and unresolved problems was the presence of dominant companies, and the

unclear measures set out in the aforementioned directive regarding how and to what extent the

problem can be resolved. In general, it seemed that there was a lack of will among Member

States and on behalf of the Commission to reduce the market power of dominant companies

(Thomas, 2006; Jakovac, 2012, p. 321).

With the Third Energy Package, Directive 2009/72/EC came into force and updated the

previous two electricity directives with the goal of accelerating the process of creating an EU

internal electricity market.

Third Electricity Directive – 2009

According to Directive 2009/72/EC, Member States have the possibility to choose among

three alternative models of unbundling. The first model is ownership unbundling, meaning

that supply and production companies cannot hold a majority stake in a TSO, nor exercise

voting rights or appoint board members. On the other hand, supply and production companies

are allowed to choose to whom and at what price they sell their networks. The second model

allows supply and production companies to own the physical network. In such cases,

however, they are obliged to delegate any operation, maintenance and investment decision to

an independent company, i.e. an independent system operator. The third model, which

employs an independent transmission system operator, allows supply and production

companies to own the network, under the condition that it is operated by a subsidiary of the

parent company that makes decisions independently of the latter (Pellini, 2014, pp. 15-16).

The Third Directive also imposes a high standard of public service obligations on Member

States, while a high level of customer protection is promoted (DG Energy – European

Commission, 2011). Member States are also obliged to define the concept of vulnerable

customers. Therefore, the categories of consumer that will qualify as a vulnerable customer

must be specified. For example, elderly consumers with extremely low income may be

considered as vulnerable in special circumstances, such as a severe winter (when they use

electricity to heat their home). A prohibition of disconnection may apply for such customer, in

the form of licence condition or obligation (European Commission, 2010, p. 6).

Within the framework of the Third Energy Package, Regulation 713/2009/EC established the

Agency for the Cooperation of Energy Regulators (ACER). ACER plays an important role

in the process of completing the IEM. It mainly complements and coordinates the work of

national energy regulators at the EU level. ACER was also allocated additional tasks

concerning wholesale energy market integrity and transparency (REMIT), as well as

guidelines for the trans-European energy infrastructure. It plays a central role in the creation

of the IEM and the enhancement of competition. Its main tasks are the coordination of

9

regional and cross-regional initiatives that favour market integration, and monitoring the IEM

in general, as well as wholesale energy trading activities (ACER, 2014).

Moreover, Regulation 714/2009/EC established the European Network of Transmission

System Operators (ENTSO): ENTSO-E for electricity and ENTSO-G for gas. ENTSO-E’s

mission is to offer security through the coordinated, reliable and secure operation of the

interconnected electricity transmission network. Its objectives are to provide a platform for

the market and to promote sustainability by facilitating the secure integration of new

generation sources. In line with its mission, it also promotes the requisite development of the

interconnected European grid (Entsoe, 2014). The work of ENTSO-E and its network

development plans are monitored by ACER.

In addition to the work of ACER and ENTSO-E, many other EU agencies and institutions

play an important role in the creation of the EU’s IEM. The first are the Directorate-Generals

(DGs) of the European Commission, which formulate and implement European policies. The

specific DGs for energy are DG Energy and Transport (DG TREN), DG Competition and DG

Environment. The second is the Electricity Regulatory Forum (Florence Forum), a forum

where parties meet twice a year to discuss the creation of the IEM. Participants include

regulatory authorities, representatives of the governments of Member States, the European

Commission, TSOs, electricity traders, customers, network users and power exchanges. The

Council of European Energy Regulators (CEER) also contributes to the facilitation of a

single, competitive and sustainable EU IEM. CEER is a non-profit organization established in

2000 to promote cooperation between independent energy regulators in Europe (Meeus et al.,

2005, p. 27; CEER, 2014; European Commission – Energy, 2014).

Each year, ACER and CEER draft a Market Monitoring Report that assesses developments on

the electricity and gas markets, as well as progress in the implementation of the Third Energy

Package. There is still room for improvement in terms of the completion of the IEM.

With regard to retail electricity markets,2 the latest Market Monitoring Report (ACER/CEER,

2014) exposed the heterogeneity of national energy policies. This is reflected in electricity

prices that are influenced by taxation and network charges, which in most cases represent

more than one half of the bill. There are major differences across the EU concerning this

issue. Moreover, on the largest EU markets (Denmark, Finland, Germany, Italy etc.), retail

markets are moderately concentrated, and thus perform relatively well (the main performance

indicators used were choice of suppliers and offers, entry-exit activity etc.). The Market

Monitoring Report reveals that customers do not participate actively in terms of supplier

switching, and consequently do not choose among different products offered on the market.

Worthy of note with regard to market players is the need to ensure transparent and reliable

online price comparison tools, as well as transparent energy invoices. This is also one of the

key barriers to entering retail markets, as perceived by suppliers. Additional barriers to enter

the market are a lack of harmonization of regulatory frameworks among Member States, the

2 Progress on the wholesale electricity markets is described in Subchapter 1.2 (Section 1.2.1 Electricity Regional

Initiative).

10

regulation of retail prices3 and the low liquidity of wholesale markets (particularly on less

developed markets) (ACER, 2014).

1.2 Regional electricity markets in the European Union

Regionally, countries share a similar economic and political environment. It is thus normal

that common rules and methods are first created and applied within a region, followed later by

pan-European integration.

In this respect, regional electricity markets (REMs) are considered a natural step in the

evolution of national electricity markets towards a fully integrated internal electricity market.

Through REMs, barriers to trade can be removed and practical solutions can be found to

increase competition within regions (Mercados, 2010, p. 20).

1.2.1 Electricity Regional Initiative

In 2006, National Regulatory Authorities (NRAs) set up the Electricity Regional Initiative

(ERI) with the support of the European Commission. The project was intended to speed up

the integration of national energy markets in Europe, and is perceived as an interim step to

complete the IEM. Initially, Regional Initiatives were launched by European Regulators’

Group for Electricity and Gas (ERGEG), following the “bottom-up” approach. The project

brought together NRAs, the European Commission, transmission system operators (TSOs)

and other relevant stakeholders in seven electricity and three gas regions (Table 1). Regional

Initiative brought good results such as the implementation of network codes, and the

exchange of information and best practices. Nevertheless, after implementation of the Third

Energy Package (2009) and with the creation of ACER, a new approach was introduced.

ACER took over the Regional Initiatives project, and now employs a new “top-down”

regulatory approach (ACER, 2013, p. 16).

Table 1. Electricity Regional Initiative (ERI)

Source: CEER, 2014.

3 “As of 31 December 2013, household end-user price regulation existed in 15 countries (out of 29)”, as follows:

Croatia, Bulgaria, Spain, France, Hungary, Latvia, Lithuania, Poland, Slovakia, Romania, Denmark, Cyprus,

Estonia, Malta, Belgium (ACER, 2014).

Region Countries

Baltic Region Estonia, Latvia, Lithuania

Central-East (CEE) Austria, Czech Republic, Germany, Hungary, Poland, Slovakia, Slovenia

Central-South (CSE) Austria, France, Germany, Greece, Italy, Slovenia

Central-West (CWE) Belgium, France, Germany, Luxembourg, Netherlands

Northern (NE-NWE) Denmark, Finland, Germany, Norway, Poland, Sweden

South-West (SWE) France, Portugal, Spain (Spain and Portugal are also called MIBEL region)

France-UK-Ireland France, Ireland, United Kingdom

11

ACER’s project promotes cooperation and the early implementation of rules at the regional

and cross-regional level. This new approach accelerates the completion of the IEM, which

was planned by the end of 2014. It started in 2010, and the goal is for electricity markets

across Europe to share a set of common features that are linked by the efficient management

of interconnection capacities (ACER, 2014).

To that end, four Target Models have been defined for electricity market integration. All

Member States are expected to implement the below described Target Models in order to

achieve improved market integration between themselves, and to facilitate cross-border

trading in all timeframes (ACER/CEER, 2014).

First Target Model: market coupling (for the day-ahead and intraday timeframe)

Using the market coupling method, energy and capacity are allocated together, while energy

prices reflect both congestion costs and energy costs. According to this method, energy flow

is always from a low price region to a high price region (Deloitte Consulting, 2013, p. 26).

Market coupling will be used instead of the method of separate capacity allocation via explicit

auctions and energy purchases/sales via an energy exchange.

The target model for the day-ahead timeframe is the European Price Coupling (EPC) model

that simultaneously determines volumes and prices for all price zones in Europe (ACER

Coordination Group for Electricity Regional Initiatives, 2015, p. 5). The markets of Austria,

Belgium, Denmark, Estonia, Finland, France, Germany, Great Britain, Latvia, Lithuania,

Luxemburg, the Netherlands, Norway, Poland and Sweden have been coupled since February

2014. Spain and Portugal have also been using the same market coupling platform since 2014,

while the aforementioned markets have been coupled since 2010. This means that market

coupling has been implemented between the NWE, MIBEL and CSE regions (ACER, 2014a).

There are ongoing discussions between Croatian, Hungarian and Slovenian counterparties

regarding the decision on which border the coupling will be implemented first. The Croatian

Power Exchange (CROPEX) was established prior to discussions. Coupling has been in place

on the Italian-Slovenian border for a few years already. Bulgaria-Romania market coupling is

in its initial phase and is expected to go live after 2015 (ACER Coordination Group for

Electricity Regional Initiatives, 2015, pp. 5-6). The exception is the Greek market, whose

wholesale market requires restructuring in the future in order to achieve harmonization with

the rest of the region.

Second Target Model: cross-border intraday

The goal is to implement an Intraday Target Model on all borders in Europe. Implementation

is based on two phases: (i) implicit continuous intraday trading and (ii) intraday capacity

recalculation, capacity pricing and the trading of sophisticated products (ACER, 2014). The

second phase actually represents the evolution of implicit continuous intraday trading.

Implementation of the Second Target Model is first planned in the NWE region. This pilot

project is run by Ofgem (UK). Later, the model will also be implemented in other regions.

12

Currently, there are major delays with the NWE pilot project, since it was planned to go live

in 2014. Certain operational and legal challenges are causing the delay (ACER Coordination

Group for Electricity Regional Initiatives, 2014, p. 7).

Third Target Model: long-term (LT) transmission rights

The objective of this project is to offer participants an opportunity to hedge against congestion

costs and day-ahead congestion pricing. In order to achieve this objective, allocation rules, the

allocation platform and nomination procedures must be harmonized. There exists a possibility

that a shift will be made to Financial Transmission Rights (FTRs) (ACER Coordination

Group for Electricity Regional Initiatives, 2014, p. 9).

Regarding the harmonization of allocation rules, ENTSO-E has prepared a set of harmonized

auction rules (EU HAR) that will be applicable from 2016. To date, the first version has been

published and is available for public consultation. With regard to the allocation platform, the

merger of the Capacity Allocation Office (CAO) and Capacity Allocation Service Company

(CASC) is planned. CASC and CAO are two major regional allocation platforms and, once

merged, will function under a new entity called the Joint Allocation Office (JAO). It is

expected that JAO will be organising the 2016 auctions.

Fourth Target Model: capacity calculation

The final objective is to implement a fully coordinated capacity calculation methodology, in

the form of an Available Transmission Capacity (ATC) or a Flow-Based (FB) method. The

second is preferable for short-term capacity calculation (ACER, 2014).

The progress made by wholesale electricity markets is assessed in the Market Monitoring

Report (ACER/CEER, 2014). The Four Target Models are therefore included as a main

component of the final IEM. As stated in the aforementioned report, one of the indicators of

market integration is the convergence of wholesale electricity prices. For example, when

market coupling was extended from the Czech Republic and Slovakia to Hungary in 2012,

electricity prices on these three markets converged significantly. Although an increase in price

convergence was expected across all EU regions, this was not the case in 2013. The CWE

region experienced a significant decrease, of 32% compared to 2012. The underlying reason

was German prices (mostly driven by renewables and coal-fired plants), which were lower

than elsewhere in the region due to cheap coal on international markets and the penetration of

renewables. Nevertheless, the recent NWE price coupling initiative “is expected to improve

price convergence across all the regions in the coming years” (ACER/CEER, 2014, p. 14).

Another positive effect of market coupling is the efficient use of interconnectors, which

recorded an efficiency rate of 77% in 2013 in the day-ahead timeframe. Nevertheless, the full

implementation of the four electricity Target Models remains a priority. The report also

highlights the need for efficient and well-integrated gas markets in order to achieve flexibility

on electricity markets. In addition, it is reported that demand-side participation can also

contribute to the flexibility of electricity markets (ACER/CEER, 2014, p. 16).

13

1.2.2 South East Europe

The so-called 8th

region or South East Europe (SEE) region covers the Energy Community

contracting parties (Albania, Bosnia and Herzegovina, the former Yugoslav Republic of

Macedonia, Kosovo, Moldova, Montenegro, Serbia and Ukraine) as well as the seven

neighbouring EU Member States (Bulgaria, Croatia, Greece, Italy, Hungary, Romania and

Slovenia) (Energy Community, 2014). Georgia is an Energy Community candidate country,

while Turkey, Armenia and Norway have been granted the status of observer.

Historically, the countries of the SEE region have shared the same energy problems such as

small energy markets, energy intensive economies and regional energy prices below

economic levels, inappropriate pricing/tariffs and poor infrastructure, as well as energy

policies that differ significantly from the EU’s policy. These common challenges triggered the

need for regional energy cooperation (Karova, 2011, p. 81).

The creation of a regional SEE energy market was proposed in 2002 with the so-called

Athens Process that included a plan to integrate the SEE market with the EU’s IEM.

Following several memorandums of understanding, the Energy Community Treaty was

finally signed in 2005, and entered into force in 2006 with ratification by all signatories

(Karova, 2011, p. 81). This was the first ever multilateral treaty signed between the EU and

South East Europe (EU candidate and potential candidate countries), with the goal of boosting

energy integration. In addition, the Energy Community Treaty will extend the EU’s IEM to

the Balkan Peninsula as a whole. Consequently, the relevant acquis communautaire4 on

energy, the environment and competition is also planned to be implemented in this area

(European Commission, 2005).

In terms of the creation of the SEE regional market and its subsequent integration with the

EU’s IEM, a special document has been developed in line with the elements of the European

Electricity Target Model, called the Regional Action Plan for Wholesale Market Opening in

South East Europe (SEE RAP). Since implementation of the EU’s IEM was planned for 2014,

the target for the SEE region is 2015. Prior to the RAP, the Third Energy Package was

incorporated into the Energy Community back in 2011, with a transposition deadline of

January 2015 (ACER Coordination Group for Electricity Regional Initiatives, 2014, pp. 19-

20). In its reports, ACER also provides details about the progress of the SEE region. The 2014

status is presented in Table 2.

4 Acquis communautaire is a term that refers to EU laws, and includes all treaties, regulations and directives

passed by European institutions, as well as the judgements handed down by the European Court of Justice. This

term is most often used in preparations by EU candidate countries, since they must adopt and implement the

entire acquis to be able to join the EU (Eurofound, 2014).

14

Table 2. 2014 SEE region status (integration with the EU’s IEM)

Source: ACER Coordination Group for Electricity Regional Initiatives, ERI Progress Report, April 2014 –

September 2014, 2014.

As presented in Table 2, progress in the regional implementation of common practices and

rules is slow. The main characteristic of the SEE region is significant heterogeneity in its

market and regulatory framework. There are some major obstacles to creating an efficient

regional market. The SEE region’s legal basis lacks harmonization and requires

implementation. Consequently, a number of legislative provisions in some countries (related

to public supply, single-buyer models, regulated energy prices, and monopolistic positions in

electricity generation and supply) are preventing the effective opening of the market.

Moreover, additional commitment is needed from major regional players in order to achieve

further improvements (ACER Coordination Group for Electricity Regional Initiatives, 2014).

There is also a need for the development of harmonized cross-border balancing and overall

transparency.

As mentioned in Table 2, an important step forward was the establishment of the SEE CAO in

2014. The office conducted its first yearly auctions for 2015 for the Bosnia-Montenegro and

Bosnia-Croatia borders, offering 200 MW and 400 MW of available capacities (in both

directions) respectively. The SEE CAO targets the harmonization of allocation and

nomination rules for long- and short-term transmission rights in the SEE region. Coordinated

NTC-based capacity allocation is initially planned, with a subsequent switch to flow-based

capacity auctioning. The office is located in Montenegro, and the shareholders of the SEE

CAO are TSOs of Greece (IPTO), Montenegro (CGES), Croatia (HOPS), Kosovo (KOSTT),

RAP element Project - Progress and issues

Harmonization of allocation and

nomination rules for long-term

(LT) and medium-term

transmission rights.

There is a lack of regional coordinated capacity allocation

mechanisms, as well as insufficient transmission

interconnection capacity with neighbouring systems.

Nevertheless, an important step was the establishment of a

coordinated auction office, the SEE CAO, which conducts

centralized and multilaterally coordinated auctions for the

largest parts of the region.

Day-ahead (DA) capacity

allocation (market coupling)

The aim is to achieve single Price Coupling (PC), which

simultaneously determines volumes and prices in all relevant

zones (marginal pricing principle). The first step is to establish

power exchanges. Announcement of a power exchange in

Serbia by EMS and EPEX spot. Greece, Italy, Slovenia,

Romania, Croatia and Hungary have established trading hubs.

Continuous mechanisms for

implicit cross-border intraday

trading

A specific cross-border continuous intraday trading system at

all borders of the 8th region has not begun to function yet,

although it was required under the EU’s Second Energy

Package.

Capacity calculation No concrete milestones for the implementation of the flow-

based allocation have been defined to date, and no concrete

steps have been taken.

15

Bosnia and Herzegovina (NOS-BIH), Albania (OST) and Turkey (TEIAS). It was pointed out

in the recent Athens Forum that the TSOs of Bulgaria, Macedonia and Serbia should

participate, and were required to draw up concrete plans for their integration (SEE CAO,

2014; ACER Coordination Group for Electricity Regional Initiatives, p. 27).

1.3 Turkish electricity market overview and its interconnection with the

SEE region

Turkey is the 16th

largest economy in the world, with its GDP reaching $820 billion in 2013,

and would have ranked as the 6th

largest economy in the EU in 2013 had it been a member. Its

population is about 76.7 million, with an annual growth rate of 1.12%. Half of the population

is under the age of 30. Projections indicate that Turkey’s population will reach 84 million by

2023 (Invest in Turkey, 2014; TurkStat, 2014).

As shown in the graphs below (Figure 2), Turkey is a growing economy, since its GDP has

grown at an exceptional rate relative to other OECD5 countries over the last decade. The

decline in GDP in 2008 and 2009 was a result of the international financial crisis, from which

Turkey recovered in 2010 (IEA, 2009, p. 2).

Figure 2. Population of Turkey and GDP growth rates for Turkey, the Euro Area and OECD

countries

Source: OECD.Stat Extracts, 2014.

The country’s energy demand is driven by increasing GDP and population. Its main energy

policy concern is thus ensuring a sufficient energy supply. In the coming years, Turkey’s

energy consumption is expected to double due to its economic growth. In 2011, its energy

production was 32.06 Mtoe, while its energy consumption was 112.46 Mtoe. The difference

5 Organization for Economic Cooperation and Development. OECD Members: Australia, Austria, Belgium,

Canada, Chile, Czech Republic, Denmark, Estonia, Finland, France, Germany, Greece, Hungary, Iceland,

Ireland, Israel, Italy, Japan, Korea, Luxembourg, Mexico, Netherlands, New Zealand, Norway, Poland, Portugal,

Slovak Republic, Slovenia, Spain, Sweden, Switzerland, Turkey, United Kingdom, United States (OECD, 2014).

0

0,2

0,4

0,6

0,8

1

1,2

1,4

1,6

1,8

58

60

62

64

66

68

70

72

74

76

Population of Turkey

Population (in millions) Growth rate

-6

-4

-2

0

2

4

6

8

10

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

GDP growth of OECD countires, Euro area and

Turkey

TurkeyEuro area (15 countries)OECD - Total

16

of 80.16 Mtoe was imported (IEA, 2009, p. 1; IEA, 2013, p. 56). The data reveal that Turkey

is dependent on imported energy, since it is limited in terms of primary energy resources.

Nevertheless, it enjoys a position as a natural bridge between the demand-rich west and

supply-rich east. Turkey’s importance on the world energy markets is growing in line with its

growth as an energy consumer (Deloitte, 2013, p. 9; IEA, 2014).

With its growing electricity demand driven by industrialization and urbanization, the Turkish

electricity market is one of the fastest growing in the world. As can be seen from Figure 3, its

electricity demand doubled over more than decade, from 128 TWh in 2000 to 246 TWh in

2013 (Deloitte, 2014, p. 5; Electricity generation & transmission statistics of Turkey for 2013,

2014). The majority of the electricity produced is distributed for industrial use (around 47%),

while the remainder goes to households (around 20%), for commercial consumption,

government consumption, illumination and other consumption needs such as the agriculture

and fishery sector (TurkStat, 2014).

Figure 3. Turkish electricity demand 1975-2013

Note: Gross demand = gross generation + import - export; net consumption = supply - network loss

Source: TurkStat, 2014.

On average, 45% of electricity is produced from natural gas, while 25% is produced from

coal. Around 20% to 25% is produced from hydro and the remaining 5% is produced from

renewable sources. Turkey does not have any nuclear energy (Electricity generation &

transmission statistics of Turkey for year 2013, 2014).

Turkey and the SEE region

As mentioned in the previous subchapter, Turkey has the status of Energy Community

observer, and has also formally expressed its interest in full membership. As an observer, it

has the right to be represented at institutional meetings and to receive any information

distributed at those meetings. Once the Energy Community Treaty is signed, Turkey agrees to

0

50000

100000

150000

200000

250000

300000

1975 1980 1990 2000 2007 2008 2009 2010 2011 2012 2013

Gross demand (GWh) Net consumption (GWh)

17

adapt EU energy standards and practices, which is also in line with its status as EU candidate

country and the related requirements (Energy Community, 2014).

Turkey is also a shareholder in the SEE CAO, and is interconnected with the SEE region via

Bulgaria and Greece. Interconnection and trading among those countries is described in

Chapter 3.2. The ENTSO-E connection6 offers Turkey new trading opportunities, while it is

widely discussed that Turkey increases the liquidity of the SEE region, since the Turkish

market is large (see Appendix C) and ENTSO-E interconnection capacities are to be 1,200

MW in the future.

Compared with the other markets of Energy Community contracting parties, Turkey’s

generation is by far the largest. In 2013, Turkey generated 240,154 GWh of electricity, while

Albania, Bosnia and Herzegovina, Macedonia, Moldova, Montenegro and Serbia produced

5,956 GWh, 16,303 GWh, 5,676 GWh, 748 GWh, 3,809 GWh, and 27,537 GWh respectively.

Markets also differ in terms of the number of end-customers. For example, Turkey has

approximately 66,505,050 end-customers, while Serbia has 3,580,579 end-customers. Since

liquidity is a key component of the wholesale electricity market, Turkey is a positive

influence for the SEE region is this respect (Appendix C).

As cross-border trading activities among Greece, Bulgaria and Turkey develop, the Turkish

electricity market will also become a role model or a benchmark for Georgia. In this way, the

Georgian electricity market can develop rapidly and its hydro potential can fully be utilized

(Deloitte Consulting, 2013. p. 23). Georgian traders will be able to access the European

electricity market and vice versa.

2 ELECTRICITY MARKET REFORM IN TURKEY

2.1 Turkish electricity market prior to reform

Prior to reform efforts, a vertically integrated company dominated the entire Turkish

electricity industry, as was the case in many other countries worldwide. The company was

called the Turkish Electricity Authority (Türkiye Elektrik Kurumu – TEK). TEK was founded

in 1970 with the main goal of unifying electricity generation, transmission, distribution and

trade under one integrated system of a state-owned enterprise (TEIAS, 2014). Subsequently in

1993, TEK was separated into two companies: the Turkish Electricity Generation Company

(TEAS) and the Turkish Electricity Distribution Company (TEDAS).

As Atiyas et al. (2012, pp. 20-21) explain, there were attempts to attract private capital to the

electricity industry in the 1980s and 1990s. In the post-World War II era, Turkey had a policy

regime that was characterized by a high level of involvement by the state in economic

activities such as the ownership of enterprises in key industries, one of them being the energy

industry. In addition, the state also played an important role in the allocation of financial

resources via state-owned banks. This regime collapsed as a result of a major balance of

payments crisis in the 1970s. The 1980s brought the liberalization of domestic markets,

6 ENTSO-E connection is the term used to refer to the Continental Europe Synchronous Area, which is an area

of interconnected markets (a TSO must be a member of ENTSO-E) that are in compliance with common

technical standards and the management of operational issues (Entsoe, 2014).

18

international trade and finance, as well as privatization being seen as a “substitute” to the

inefficient public sector. Moreover, Turkey had high public deficit in the 1990s. The Turkish

government thus wanted to attract private capital to the electricity industry to cover the high

costs of investments needed to build new electricity capacities. These new capacities were

needed due to forecasts of high growth in electricity demand.

The privatization of TEK was envisaged through different development plans over the years,

with an important attempt to privatize TEK in 1994 through the sale of ownership rights. The

privatization was blocked by the Constitutional Court due to its concerns regarding foreign

ownership in a strategic industry, and possible monopolization and cartelization. Private-

sector presence in Turkey’s electricity industry was legally enabled for the first time in 1984

under Law No. 3096. The aforementioned law introduced two types of contracts, BOT (build-

operate- transfer) contracts for new generation facilities and TOR (transfer of operating

rights) contracts for existing generation and distribution facilities. An autoproducer system

was also formed for companies to produce their own electricity. Subsequently, under Law No.

4283, a third type of contract was introduced, the BOO (build-operate-own) model (Atiyas et

al., 2012, p. 21; Cetin & Oguz, 2007, p. 1763).

BOT, TOR and BOO contracts were signed between a private company and state-owned

TEAS or TEDAS. They all included an exclusive “take or pay” obligation with fixed

quantities and prices (or price formulas) for a period of 15 to 30 years (Atiyas & Dutz, 2005,

p. 8).

The specifics of each contracts are as follows (Cetin & Oguz, 2007, p. 1763):

BOT (build-operate-transfer)

Under such a contract, concession is granted to a private company, whereby the company may

build and operate a power plant for up to 99 years (later reduced to 49 years). After this

period, it is transferred to the state at no cost. In 1994, these contracts also included treasury

guarantees and tax exemptions, making them more interesting.

TOR (transfer of operating rights)

This type of contract enables a private company to operate an already existing government-

owned facility via a lease-type agreement.

BOO (built-operate-own)

This type of contract entails the construction and operation of new thermal power plants,

introduces a licensing system rather than concession, and also provides treasury guarantees.

At the end of the contract period, the investor retains ownership of the facility.

There were several serious shortcomings related to these contracts, as some of contracts were

awarded on the basis of bids from preselected companies. There were irregularities in both the

design and implementation of the contracts. Overall, they did not contribute to the

development of competitive electricity markets, since producers did not need to compete on

the market due to the “take or pay” clause. This structural problem and dissatisfaction with

the BOT, TOR, BOO model led to the search for more competitive electricity supply models

19

(Atiyas et al., 2012, p. 23). In 2001, a more fundamental approach for introducing competition

to the market was adopted under the Electricity Market Law (EML) No. 4628. The EML was

accompanied by the Strategy Paper of 2004 (Bagdadioglu & Odzakmaz, 2009, p. 145). Both

documents will be explained in more detail in the following chapter of this thesis.

In addition, foreign influence also played an important role in the introduction of competition

to the market and the implementation of structural changes. Various international institutions

such as the International Monetary Fund (IMF), World Bank and OECD, which supported

Turkey during its economic crises, highlighted the need for energy market reform. Moreover,

reform is a precondition for Turkey’s longer-term objective of EU membership (Erdogdu,

2006, p. 986). Consequently, the EML was also drafted in line with the EU Energy Acquis.

2.2 Institutional framework

2.2.1 Electricity Market Law No. 4628

The regulatory framework that introduced competition to the Turkish electricity market is

Electricity Market Law (EML) No. 4628, published in 2001. It set out a new framework for

the organization of the Turkish electricity market, and was the first law to bring concrete

reform to the market. It was in line with the 1996 EU Electricity Directive. The main

principles and objectives of the EML are described below.

Unbundling of public assets

Through reform measures, public assets were unbundled into separate public companies.

TEAS was separated into three companies: Electricity Generation Company (EUAS) for

electricity generation, Turkish Electricity Trading and Contracting Company (TETAS) for

wholesale trade activities and Turkish Electricity Transmission Company (TEIAS) for

transmission activities (Figure 4). The assets of EUAS and TEDAS were earmarked for

privatization (Bahce & Taymaz, 2007, p. 1604; Atiyas et al., 2012, p. 24). All unbundled

companies remained publicly owned at that time.

Figure 4: Unbundling of public assets

2001 1994 1970

TEK - vertically integrated

TEDAS - Distribution

TEDAS - Distribution

TEAS - Generation,

Transmission and Trade

TEİAS - Transmission

TETAS - Trade

EUAS - Generation

20

Source: EMRA, Electricity Market Report 2010, n.d., p. 3.

Establishment of an independent regulator

The Electricity Market Regulatory Authority (EMRA) was established under the EML as an

“independent, administratively and financially autonomous public institution” as described by

the aforementioned law itself. It has its own board comprising nine members and a president,

all appointed by the Council of Ministers for a period of six years. EMRA was also given the

authority over the natural gas and oil market, and was thus renamed the Energy Market

Regulatory Authority (Atiyas et al., 2012, p. 23). Its main objectives are to ensure the

development of financially sound and transparent energy markets, to promote a competitive

environment and to deliver environmentally friendly, low-cost energy to customers. In order

to pursue its objectives and to ensure that market participants comply with the relevant rules

and regulations, EMRA supervises and imposes penalties if necessary. It also assures non-

discriminatory third-party access to grids and other monopolistic infrastructures (EMRA, n.d.,

p. 11).

EMRA also drafts secondary legislation and is responsible for the implementation of a new

transmission and distribution code. Another of its tasks is to determine the threshold level for

eligible customers over time and the protection of customers’ rights (Erdogdu, 2006, p. 987).

New wholesale market model

The market model presented under the EML comprises two elements, one being a market for

bilateral contracts and the other being a balancing mechanism, established in order to ensure

balancing between the demand side and supply side. This new model became operational in

2006, while no spot market was mentioned in the law (Atiyas et al., 2012, p. 24).

In 2004, an “Electricity Sector Reform and Strategy Paper” was released by the Turkish

government, outlining the major steps to be taken (at that time) in order to achieve

liberalization of the sector. The Strategy Paper states that the balancing and settlement

mechanism is in line with the objective of creating a spot market and includes price signals to

attract new investments. In addition, the balancing and settlement regime offers the possibility

of buying and selling the non-contracted generation (Republic of Turkey – High planning

Council, 2004, p. 5). In practice, the system functioning under this model was not transparent,

since no crucial information was published (e.g. maintenance of generation units, volume of

concluded transactions etc.). There was no spot market at that time, but only a platform that

enabled balancing between the demand side and supply side.

Licensing framework for market participants

Any legal entity wanting to engage in any electricity market activity is obliged to obtain a

license. Licenses are issued for a minimum period of 10 years and a maximum period of 49

years. There are five types of licenses (Electricity Market Law No. 4628, Official Gazette,

No. 24335):

21

a. Generation license: Each facility must obtain a generation license, except for autoproducer

groups and those entities that generate electricity only to meet their own needs and do not

operate in parallel with the transmission and distribution system. Generation companies are

also allowed to enter into an affiliate relationship7 with distribution companies, without

exercising control over them.

b. Transmission license: The license obtained by TEIAS in order to perform its transmission-

related activities. It is also pointed out that TEIAS can not engage in any other activities on

the market.

c. Distribution license: The license obtained by any legal entity that wishes to engage in

distribution activities in a specific region.

d. Retail sales license: The license obtained by legal entities in order to sell electricity and

offer retail sales services to the market. In addition, the import of electricity below the

transmission level is permitted, taking into account technical issues. Retail sales are allowed

in any region, while distribution companies that hold a retail license may only sell electricity

and capacities to an eligible customer in another distribution company’s region if their retail

license includes such a provision.

e. Autoproducer and Autoproducer Group License: The license obtained by an autoproducer

that generates electricity for its own needs.

Eligible customer concept

The EML also initiated the liberalization of the demand side. The concept of an eligible

customer was defined, while the board of EMRA determines the threshold level each year.

Customers who consume more than 9 GWh a year were designated as eligible customers free

to choose their suppliers (Atiyas & Dutz, 2004, p. 10). The threshold level was later decreased

gradually. The current status of market openness is explained in Chapter 3.4.

Although the EML brought changes to the market, amendments to the aforementioned law

were necessary in order to achieve a higher level of competition on the market. In 2008, the

EML was amended by Law No. 5784. Under the amended EML, the development of

competition is stipulated in several provisions, including a provision requiring accounting

separation for operators who hold more than one license (operators must keep different

accounts for different activities or plants). Another important provision is that the total market

share of a generating company and its affiliates cannot exceed 20% of total installed market

capacity. Moreover, holders of a distribution or transmission license are required to provide

non-discriminatory system access and the use of system rights to all natural persons and legal

entities (Atiyas et al., 2012, p. 25).

7 An affiliate relationship is a situation where one company owns less than a majority of another company’s

shares. It can also be a type of relationship where at least two companies are subsidiaries of a larger company. In

Turkey, for example, a generation company could have owned a part of a distribution company (Investopedia

dictionary - Affiliate, 2015).

22

With regard to the amended EML, the Energy Community Secretariat reported full

compliance with EU Directive 2003/54/EC in November 2008, except for cross-border

trading (EBRD, n.d., p. 165).

2.2.2. New Electricity Market Law No. 6446

In 2013, a new law regulating the Turkish electricity market was enacted: Electricity Market

Law No. 6446 (new EML). It repealed and replaced all provisions of the previous EML. The

primary objective of the new EML is the establishment of a financially robust, stable,

competitive and transparent electricity market, with an independent regulatory and auditing

mechanism. The new EML is also expected to create an environment that will attract

investments in the electricity generation sector. Another important aim is to increase private-

sector presence in the electricity sector (Karaduman & Avcisert, 2013). The main new

features in the sector are explained below.

New licensing framework

The new EML focuses more on types of electricity market activities rather than types of

licences. Article 4 of the new EML lists generation, transmission, distribution, wholesale,

retail sales, market operation, export and import as activities that require a license. In contrast

to the previous EML, it does not mention retail sales services and trade activities, and

introduces market operation as a new type of activity (Erdem & Erdem, 2013).

There is a new, preliminary license for generation required for any legal entity that plans to

commence generation activities. The aforementioned license applies to the performance of

electricity generation activities. The preliminary license is issued for a specific term, not to

exceed 24 months. During this period, a legal entity must obtain the necessary permits,

approvals and licenses, and acquire ownership of or usufruct rights relating to the land where

the facility is to be constructed or located (Erdem, 2013).

A supply license is an additional amendment to the types of licences. It combines wholesale

and retail sales activities under one license type. Holders of this license have no regional

restrictions in regards to eligible customers (Çakmak Avukatlık Bürosu, 2013, p. 1).

In summary, there are several types of licenses under the new EML: preliminary license,

generation license, supplier license, distribution license, transmission license, market

operation license, OIZ8 preliminary license, OIZ generation license and OIZ distribution

license. Currently, all market players are operating under the new license system.

Electricity market operation activities

8 OIZ – “Organized industrial zone legal entities established in accordance with Organized Industrial Zones Law

No. 4562 may engage in distribution and/or generation activities in approved areas to meet the needs of its

participants, without the obligation of incorporation according to the Turkish Commercial Code No. 6762,

provided that they obtain a license from EMRA. OIZ legal entities are deemed eligible customers regardless of

their consumption quantities. Customers exceeding the eligibility threshold have the right to choose their

suppliers, provided that they pay a distribution fee to the OIZ.” EMRA (2012).

23

Activities relating to the organization of the wholesale market and the financial settlement of

wholesale market activities are planned to be performed by the newly established Energy

Markets Operation Joint Stock Company (Enerji Piyasaları İşletme Anonim Şirketi, EPIAS),

instead of TEIAS (Ergun Benan & Burcu Tuzcu, 2014).

Competition

The new EML also aims to create a competitive environment and to prevent monopolistic

situations on the market. In this regard, three important provisions are included in the

aforementioned law and affect all license holding companies. One is that generation

companies “may not hold a total installed capacity of more than 20% of the previous year’s

calculated total installed capacity in Turkey”. Another important provision is that supply

license holders may not purchase electricity from generation or export companies that exceeds

20% of the previous year’s total consumption in Turkey. The third provision, aimed at

encouraging competition, is that supply companies may not sell electricity at the wholesale or

retail level that exceeds 20% of the previous year’s total consumption of electricity in Turkey

(Erdem, 2014).

2.3. Privatization

The reform of the Turkish electricity market is based on the privatization of distribution assets

(TEDAS), followed by the privatization of generation assets (EUAS) as a resulting step. The

privatization strategy is presented in the “Electricity Sector Reform and Privatization Strategy

Paper” (Strategy Paper) from 2004. The Privatization Administration of the Republic of

Turkey is responsible for all procedures relating to the implementation the privatization

strategy.

2.3.1 Privatization of distribution companies

The privatization of TEDAS started with the division of the Turkish electricity distribution

network into 21 regions. TEDAS then established 20 new companies (one region – Kayseri –

was already privately run), based on technical, financial and geographical factors. Each of the

21 companies was engaged in distribution and retail sales activities to end-customers, and

operated as a regional monopolist in its own region. According to the Strategy Paper, these

companies were to be privatized by no later than the end of 2006. Due to some delays in the

privatization process, additional procedures were initiated in 2008 and a new Strategy Paper

was published in 2009. Today, all regions are run by private companies (Çelen, 2013, pp.

675-676). The regions and companies established by TEDAS are shown in Table 3, together

with their privatization status. It can be noted that regions no. 18, 19 and 20 were privatized in

2009 separately from the privatization procedure of the Privatization Administration. The

remaining 18 companies were privatized via tender procedures.

Table 3. Electricity distribution regions in Turkey, distribution companies and the

privatization thereof

Region Provinces Status

24

1 Diyarbakir, Mardin, Siirt, Sanliurfa, Batman,

Sirnak (Dicle Elektrik Dağıtım A.Ş.)

Privatized by Is Kaya

2 Bitlis, Hakkari, Mus, Van (Van gölü Elektrik

Dağıtım A.Ş)

Privatized by Türkerler

Table continues

continued

Region Provinces Status

3 Agri, Erzincan, Erzurum, Kars, Bayburt,

Ardahan, Igdir (Aras Elektrik A.Ş.)

Privatized by Kiler Holding – Çalık

Enerji

4 Artvin, Giresun, Gumushane, Rize, Trabzon

(Çoruh Elektrik Dağıtım A.Ş.)

Privatized by Aksa Elektrik Perakende

Satış A.Ş

5 Bingol, Elazig, Malatya, Tunceli (Fırat Elektrik

Dağıtım A.Ş)

Privatized by Aksa Elektrik Perakende

Satış A.Ş.

6 Sivas, Tokat, Yozgat (Çamlıbel Elektrik

Dağıtım A.Ş)

Privatized by Kolin-Limak-Cengiz

7 Adana, Mersin, Osmaniye, Hatay, Gaziantep,

Kilis (Toroslar Elektrik Dağıtım A.Ş.)

Privatized by Enerjisa (Sabancı – E-

on)

8 Kirsehir, Nevsehir, Nigde, Aksaray, Konya,

Karaman (Meram Elektrik Dağıtım A.Ş.)

Privatized by Alarko-Cengiz

9 Ankara, Kirikkale, Zonguldak, Bartin, Karabuk,

Cankiri, Kastamonu (Başkent Elektrik A.Ş.)

Privatized by Enerjisa (Sabancı – E-

on)

10 Antalya, Burdur, Isparta (Akdeniz Elektrik A.Ş.) Privatized by Kolin-Limak-Cengiz

11 Izmir, Manisa (Gediz Elektrik Dağıtım A.Ş.) Privatized by Elsan-Tümaş- Karaçak

12 Balikesir, Bursa, Canakkale, Yalova (Uludağ

Elektrik Dağıtım A.Ş)

Privatized by Kolin-Limak-Cengiz

13 Edirne, Kirklareli, Tekirdag (Trakya Elektrik

Dağıtım A.Ş)

Privatized by IC Holding

14 Istanbul Ili Anadolu Yakasi (İstanbul Anadolu

Yakası Elektrik Dağıtım A.Ş)

Privatized

15 Sakarya, Bolu, Duzce, Kocaeli (Sakarya Elektrik

Dağıtım A.Ş.)

Privatized by

Akkök-Akenerji-CEZ

16 Afyon, Bilecik, Eskisehir, Kutahya, Usak

(Osmangazi Elektrik Dağıtım A.Ş.)

Privatized by Yıldızlar SSS Holding

17 Istanbul Ili Rumeli Yakasi (Boğaziçi Elektrik

Dağıtım A.Ş.)

Privatized by Kolin-Limak-Cengiz

18 Kayseri Keyseri Elektrik Dağıtım A.Ş. - the

distribution company of Kayseri region was

already partially private.

The company has held operating rights

since 1990. In 2009, the contract of

the company was renewed and a

license was granted.

19 Aydin, Denizli, Mugla (Menderes Elektrik

Dağıtım A.Ş)

Privatized under Law No. 3096

20 Adiyaman, Kahramanmaras (Göksu Elektrik

Dağıtım A.Ş)

Privatized under Law No. 3096

21 Amasya, Corum, Ordu, Samsun, Sinop

(Yeşilırmak Elektrik Dağıtım A.Ş)

Privatized by Çalık Enerji

25

Source: Republic of Turkey – High planning Council, Electricity sector reform and privatization strategy paper ,

2004; A. Çelen, The effect of merger and consolidation activities on the efficiency of electricity distribution

regions in Turkey, 2013, p. 675; Atiyas et al., Competition and Regulatory Reform in the Turkish Electricity

Industry. 2012, p.32; Deloitte Türkiye, The Energy Sector: A Quick Tour for the Investor, 2013.

The privatization of distribution companies was carried out using a TOR-backed Share Sale

model (TSS model). Following the TSS model, an investor is the sole owner of the shares of

the distribution company and is granted a license for the distribution of electricity in the

designated region. On the other hand, the investor does not hold ownership of the distribution

network; that remains with TEDAS (Lazard, pp. 1-3).

As explained by Mr Mustafa Gozen (September 2014), from EMRA, via email

communication, distribution companies were required to unbundle retail sales and generation

activities under Law No. 4628, which coincided with the privatization procedure. Distribution

companies were required to establish a separate company for retail sales activities, and to

obtain a retail sales license. Effective at the beginning of 2013, distribution utilities were

legally unbundled, meaning that distribution companies operate under a distribution license,

while retail companies perform retail activities under a supplier license. Prior to 2013,

distribution companies covered all of the above mentioned activities. Effective January 2016,

distribution companies will not be permitted to purchase administrative and support services

such as accounting or finance from the companies under the control of the main company.

They will also be required to use a different physical environment and information systems

infrastructure for their distribution and retail companies.

With regard to revenues from the privatization of distribution assets, it is estimated that total

revenue reached the primary goal of raising 10.4 billion Turkish Liras (approximately $7

billion) in order to boost investment in the industry (Invest in Turkey, 2014).

2.3.2 Privatization of generation assets

The privatization of distribution assets was given priority in the privatization process. After a

delay, all assets were finally privatized in 2013, while the privatization of generation assets

continues.

In 2008, the Privatization Administration (PA) grouped larger power plants into nine

portfolios that comprised three thermal portfolios, four hydro portfolios and two mixed

portfolios. Although the plan was to sell assets by portfolios, the PA shifted from a portfolio

model to the tendering of large-scale thermal power plants separately with the aim of

maximizing value and avoiding the risk of tenders being cancelled (as was the case with

motorways and bridges because bids were too low). According to the new model, the Kangal

(457 MW), Kemerköy (630 MW), Yeniköy (420 MW) and Çatalağzı (300 MW) thermal

plants, in addition to the Hamitabat (1,156 MW) and Seyitömer (600 MW) plants, were

tendered separately, as presented in Table 4. Thermal power plants are the priority for the PA

in the privatization process (Durakoğlu, 2014; EUAS, 2015).

26

Table 4. Privatization of major thermal power plants 2013-2014

Source: Republic of Turkey Prime Ministry – Privatization Administration, 2014; Today's Zaman – Business,

2015; Invest in Turkey – The Republic of Turkey prime ministry investment support and promotion agency, 2014.

In addition to the above successful privatization procedures, three thermal power plants were

privatized in 2015. Konya Seker privatized the 990 MW Soma thermal power plant with a bid

of $685.5 million. In addition, Celikler Taahhut privatized the 210 MW Orhaneli and 365

MW Tuncbilek thermal power plants with a bid of $ 521 million (Konya Seker also bid for

these two plants, but the highest bidder was Celikler Taahhut) (Equities.com, 2015).

Many other smaller plants (all hydroelectric or so-called “run-of-river” power plants) have

also been privatized. In 2008, nine power plants with a total installed capacity of 141 MW

were privatized. Later in 2010, 18 portfolios with a total installed capacity of 140 MW were

also tendered. However, only 10 portfolios were actually privatized, while other tenders were

cancelled. Those were tendered again in 2012 and all were successfully privatized. The most

recent successful privatization of hydroelectric power plants was completed in 2014. This

include five hydroelectric power plants: Esendal, Isıklar (Visera), Kayaköy, Dere and İvriz.

All were privatized under the TOR model for a period of 49 years (Republic of Turkey Prime

Ministry – Privatization Administration, 2014).

Power plant Privatization process and new owners Value

Kangal (457 MW) Privatized by Konya Seker (local sugar producer that offered $985

million for privatization) via the “asset sale” method. Privatization

was completed in August 2013.

$985

million

Kemerköy

(630MW) and

Yeniköy (420

MW)

The movable properties of the plant will be privatized via the

“asset sale” method, while the immovable properties used by the

Kemerköy and Yeniköy thermal power plants and the immovable

properties used by YLİ were privatized via the same method. The

procedures were completed in December 2014. The plant operates

as a subsidiary of ICTAS Energy Generation and Trade Inc.

$4.3

billion

Çatalağzı (300

MW)

Privatized by Çates Elektrik Üretim A.Ş. via the “asset sale”

method. Privatization was completed in December 2014.

$351

million

Hamitabat (1,156

MW)

Privatized by Limak Doğalgaz Elektrik Üretim A.Ş. via a block

sale in the form of the sale of 100% of shares. Agreements were

signed in August 2013.

$105

million

Seyitömer (600

MW)

Privatized by Elektrik Üretim A.Ş. via the “asset sale” method,

while mine fields were privatized using the TOR model.

Agreements were signed in June 2013.

$2.24

billion

27

Through past successful privatization procedures, the market share of EUAS has been

gradually reduced, from 57% in 2006 to 37% in 2013 (Figure 5), and continues to decline.

The private sector is expected to hold a higher market share in the future.

Figure 5. Proportion of Turkey’s total installed capacity accounted for by EUAS 2006-2013

Source: Electricity generation & transmission statistics of Turkey for year 2013, 2014.

3 TURKISH ELECTRICITY MARKET ANALYSIS

3.1 Generation

There are five types of market players on the Turkish electricity generation market (Ergun

Benan & Burcu Tuzcu, 2014):

1. State-owned EUAS with its subsidiaries and affiliated partnerships.

2. Build-operate-transfer (BOT) and build-operate-own (BOO) companies. These companies

operate under a concession (BOT) or license (BOO) agreement signed between the state

and a private company. They do not require a generation license, since their operations are

based on agreements with the Ministry of Energy and Natural Resources (MENR) and

public authorities.

3. Companies operating under a transfer-of-operating-rights (TOR) agreement. The

generation utility is owned by the state and operated by a private entity.

4. Independent power producers (private entities).

5. Autoproducers.

0%

10%

20%

30%

40%

50%

60%

2006 2007 2008 2009 2010 2011 2012 2013

EUAS AFFILIATED PARTNERSHIPS OF EÜAŞ

PRODUCTION COMP. AUTOPRODUCERS+TOOR

28

As Table 5 illustrates, around 37% of installed capacity in Turkey is owned by EUAS or its

affiliated partnerships and subsidiaries. The remaining 63% of installed capacity is managed

(and in some cases owned) by private companies. From a management point of view, the

sector is dominated by private companies. However, when BOT and TOR agreements are

taken into account (i.e. the state is or will be the owner of these utilities), the state is a major

player on the generation market in terms of ownership.

Table 5. Distribution of installed capacity by primary energy resources and market share of

electric utilities in Turkey, 2013

Source: Electricity generation & transmission statistics of Turkey for year 2013, 2014.

According to MENR (2014), BOO, BOT and TOR contracts enjoyed market shares of 9.5%,

3.6% and 1.5% respectively in 2013. Most of the capacities added to the system in 2013 were

built by the private sector. In total, this is 6,985 MW of installed capacity, comprising 86

hydro power plants, 29 thermal plants, 11 wind plants, 10 landfill gas and biogas plants and

four geothermal plants (MENR, 2014). Turkey is therefore promoting a higher private sector

presence and is making an effort to reduce the market share of EUAS.

Currently, a large proportion (44%) of electricity consumed in Turkey is generated from

natural gas power plants, followed by coal (27%) and hydropower (25%) electricity

generation. A smaller proportion (4%) is generated from renewable energy sources such as

wind and geothermal energy (see Figure 7). Turkey is planning to make specific changes in its

UTILITIES

PRIMARY ENERGY RESOURCES

(MW)

EUAS AFFILIATED

PARTNERSHIPS

OF EUAS

AUTOPRODUCERS

& PRODUCTION

COMPANIES (BOO,

BOT included) &

TOR

TOTAL

(MW)

COAL: HARD COAL + IMPORTED COAL + ASPHALTITE 300 4,083 4,383

COAL: LIGNITE 3,690 2,714 1,819 8,223

LIQUID FUELS: FUEL OIL + DIESEL OIL + LPG +

NAPHTHA

50 566 616

LIQUID FUELS: NATURAL GAS 1,432 15,739 17,171

RENEWABLES AND WASTES 0 235 235

TOTAL SINGLE FUEL-FIRED 5,472 2,714 22,442 30,628

SOLID + LIQUID 367 367

NATURAL GAS + LIQUID 2,676 4,731 7,407

NATURAL GAS + LIQUID + SOLID 245 245

TOTAL MULTI FUEL-FIRED 2,676 0 5,343 8,019

THERMO TOTAL (SINGLE FUEL-FIRED + MULTI FUEL-

FIRED)

8,149 2,714 27,785 38,648

HYDRO TOTAL 12,918 9,371 22,289

GEOTHERMAL TOTAL 311 311

WIND TOTAL 2,760 2,760

GENERAL TOTAL (MW) 21,067 2,714 40,227 64,008

ELECTRIC UTILITY MARKET SHARE (%) 32.9 4.2 62.9 100

29

electricity generation mix by 2023. The country is aiming to increase the proportion of total

energy sources accounted for by renewable energy sources from 20% to 30% by 2023 (Baris

& Kucukali, 2012, p. 390). It is also aiming to make two nuclear power plants operational

over the long term, although Turkey currently does not have any nuclear power plants. Two

major planned projects are the Akkuyu nuclear power plant project (4,800 MW planned

installed capacity) and the Sinop power plant project (4,480 MW planned installed capacity).

The target is to produce 5% of electricity from nuclear energy by 2020 (MENR, 2014). The

primary goal is to reduce the country’s dependency on imports.

Figure 6. Electricity generation in Turkey by primary resources, 2013 in percentages

Source: Electricity generation & transmission statistics of Turkey for year 2013, 2014.

A well-functioning generation segment of the electricity market, which complies with EU

legislation, is essential for the whole electricity industry, since it represents the basic

component of the final retail and wholesale price. Current arrangements of the Turkish

electricity generation market are presented by the type of energy source below.

3.1.1 Natural gas

As presented in Figure 6, the majority of electricity in Turkey is produced from natural gas.

This link between the two markets affects electricity prices (as presented in the Chapter 4.2).

It is therefore necessary to present an overview of natural gas market dynamics and to

understand the functioning of the market.

Prior to reform in 2001, the Turkish natural gas market was dominated by the vertically

integrated, state-owned BOTAS. The company built natural gas pipelines and related

facilities, signed long-term natural gas sale and purchase agreements, and also purchased

natural gas on foreign spot markets. At that time, distribution companies (state and privately

owned) were able to distribute gas, but were unable to import gas from another supplier by

bypassing BOTAS. Consequently, the main driver of reform was the introduction of

competition on the wholesale market (Atiyas et al., 2012, p. 65).

[CATEGORY

NAME]

26.6

[CATEGORY NAME]

43.8

[CATEGORY NAME]

1.20

[CATEGORY

NAME]

24.70

[CATEGORY NAME]

0.60

[CATEGORY NAME]

3.10

30

In 2001, Natural Gas Market Law No. 4646 entered into force with the aim of restructuring

the market from a monopolistic structure to a liberalized market with competitive elements.

Although the aforementioned law required the state-owned BOTAS to reduce its market share

in the import, wholesale and distribution segments, it continues to remain a dominant market

player (IEA, 2013b, p. 14; EMRA, 2012, p. 8). The current market structure is presented in

Figure 7.

Figure 7. Turkish natural gas market structure

Source: Deloitte Türkiye, The Energy Sector: A Quick Tour for the Investor 2013, 2013, p. 42.

Turkey’s domestic production contributes only 2% to total natural gas consumption. The

country therefore imports the remaining 98% of natural gas, meaning it is completely

dependent on natural gas imports. Its natural gas and LNG import partners are Russia, Iran,

Azerbaijan, Algeria and Nigeria. As shown in Table 6, Turkey’s first international agreement

was signed with Russia, which led to the construction of the first main natural gas

transmission line, extending from the Bulgarian border to Ankara (Melikoglu, 2013, p. 394;

Natural Gas Europe, 2014). Russia is also the largest natural gas contract partner of Turkey,

since more than 55% of total Turkish natural gas consumption is imported from Russia.

Table 6. Natural gas and LNG sale and purchase agreements (BOTAS)

Original contract volumes/maximum

capacity

Consumption estimates and costs

for 2013 – major natural gas

contracts

Exploration, production and

import Transmission Storage Wholesale

Distribution and retail

Private sector NG

import companies

BOTAS – trade

Private sector LNG

import companies

Eligible

customers

BOTAS –

balancing and

gas for own use

NG distribution

companies

Private sector

wholesale

companies

Storage

companies

Local

production

31

Agreement Volume (bcm/year) Date of

signature/end date

Consumption (bcm) –

as % of total natural

gas consumption

Cost ($

billion) – as

% of import

costs

Algeria (LNG) 4.4 1988/October 2024 - -

Nigeria (LNG) 1.3 1995/October 2021 - -

Iran 9.6 1996/July 2026 8.568 bcm – 18% $4.88 billion

– 21.2%

Table continues

Continued

Agreement Volume (bcm/year) Date of

signature/end date

Consumption (bcm) –

as % of total natural

gas consumption

Cost ($

billion) – as

% of import

costs

Russian Fed. (Black

Sea) – “Blue

Stream”

16 (1986 – first

agreement)

1997/end of 2025

27.132 bcm – 57% $11.02

billion –

47.9%

Russian Fed.

(western line)

14 (4 by BOTAS,

10 transferred to

private sector)

1998/end of 2021

Azerbaijan (Phase –

I)

6.6 2001/April 2021 4.284 bcm – 9% $1.63 billion

– 7.1%

Azerbaijan (Phase –

II)

6 2011/start in

2017/2018, until

2032/2033

- -

Domestic natural

gas

- - 0.952 bcm – 2% n/a

SPOT LNG - - 6.664 bcm – 14% $5.47 billion

– 23.8%

Source: Botas, 2014; Natural Gas Europe, 2014.

As evident from Table 7, Iranian gas is the most expensive for Turkey, and represents a

source of tension between the two countries. Turkey buys gas from Iran at a price of

$507/tcm. This price was agreed after an arbitration procedure in 2009 that was concluded in

favour of BOTAS. The procedure covered retrospective price revision in the framework of a

discount rate determined by the International Court of Arbitration.9 Turkey was also awarded

$800 million in compensation relating to natural gas purchases from Iran. Moreover, BOTAS

filed a request in 2012 for the cessation of gas imports from Iran due to low gas quality, while

arbitration procedures are in progress at the ICC, since Turkey wants to lower the Iranian

price (Oxford, 2014, p. 29).

Table 7. Natural gas prices for Turkey 2012–2013 (for BOTAS)

9 The court is a branch of the International Chamber of Commerce (ICC).

Agreement Price in 2012, $/tcm Price in 2013, $/tcm (Discount in 2013)

32

Source: G. Rzayeva, Natural Gas in the Turkish Domestic Energy Market: Policies and Challenges 2014, p. 29;

Table adopted from ZAMAN.

In addition, Turkey buys Russian gas at a discount rate, since Russia applied discounts to its

European customers in 2013. Nevertheless, the cheapest natural gas is imported from

Azerbaijan, at a price of $349/tcm (Table 7).

All gas contracts are characterized by a “take or pay” obligation, meaning that Turkey is

obliged to take a minimum pre-specified proportion of the contracted volume each year, or it

pays for the gas even if not taken (Rzayeva, 2014, p. 22).10

As reported by the “Natural Gas

Europe” organization (Natural Gas Europe, 2014), Turkey will abandon this obligation for

Azerbaijani gas in the coming year, and for Iranian gas in the coming months. It has also been

reported that Turkey abandoned similar clauses for gas supplies from Russia in 2013.

The above described import dependency is leading to concerns about meeting seasonally

volatile gas demand, with an absence of sufficient underground storage capacity. In addition,

supplier or transit countries could curtail agreed volumes for economic or political reasons (as

was the case in 2006, when Ukraine and Iran cut gas exports to Turkey, and in January 2007

and 2008, when Iran reduced the supply of gas twice). When such gas supply interruptions

occur, there is a risk of power shortages due to the interdependence of the natural gas and

electricity markets. This can be mitigated by the construction of new storage facilities and the

diversification of sources (Atiyas et al., 2012, p. 66).

Import dependency is crucial for understanding the Turkish natural gas market and its

connection to the electricity market. Nevertheless, other segments of the natural gas market

are also important in order to understand the market fully, as explained below (IEA, 2013b,

pp. 14-17, Rzayeva, 2014, p. 32; Atiyas et al., 2012; EMRA, 2012, p. 34; PwC Turkey, 2014,

p. 8):

BOTAS market share: Under the law passed in 2001, BOTAS is obliged to gradually

transfer its import contracts with the aim of reducing its market share to 20% of annual

consumption. Consequently, a small portion of natural gas imports from Russia was

transferred to seven private companies (in total 10 bcm).11

Nevertheless, BOTAS

currently holds an 80% market share, while the remaining 20% is in the hands of private

companies. It is a widely accepted view that it is unrealistic to expect the market share of

BOTAS to be reduced to 20%. The amended law from 2013 proposes a reduction to 50%,

while there is no specified deadline for BOTAS.

10

Gas not taken may, however, be taken in a make-up period of 4-5 years. 11

Enerco Enerji (2.5 bcm), Bosphorus Gaz (0.75 bcm; additional 1.75 mcm in 2012 tender), Avrasya Gaz (0.5

bcm), Shell Enerji (0.25 bcm), Akfel (2.25 mcm, Kibar Enerji (1 mcm), Bati Hatti (1 mcm).

Iran 530 507 (4.34%)

Russia (Western Line) 446 429 (3.81%)

Russia (Blue Stream) 445 428 (3.82%)

Azerbaijan 354 349 (1.41%)

33

LNG imports: There are two LNG terminals in Turkey (used for storage, gasification and

transmission). One is the Marmara Ereglisi LNG Terminal, owned and operated by

BOTAS (in operation since 1994 under agreement with Algeria). The second is the Ege

Gaz A.Ş. LNG Terminal at Aliaga (in operation since 2006 and operated by the private

company Ege Gaz).

Storage: The country has approximately 3 bcm of storage capacity, which is planned to be

increased due to the increasing demand for gas.

Wholesale market: There are 42 wholesale companies in Turkey that are not allowed to

engage in transmission and distribution activities. Their sales quantities are limited to less

than 20% of projected consumption, while they are also required to maintain storage

capacities.

Retail market: There are 63 distribution companies that are obliged to purchase natural

gas from at least two different sources.

Eligible customers: The threshold level is set to zero for all household customers, except

for those who consume less than 100 tcm a year. Inner-city distribution companies have

an eligible customer limit of 15 mcm per year for the first five years of operations (since

they charge a higher distribution fee to non-eligible customers). Ankara’s recently

privatized, Baskent Gaz inner-city distribution network enjoys a special eligible customer

limit of 800 tcm until August 2017.

Pricing (BOTAS): In 2008, BOTAS was included in a cost-based pricing mechanism that

applies to state-owned enterprises. BOTAS was able to set its wholesale prices for

distribution companies and for eligible customers, and was therefore required to publish

its tariffs on a monthly basis (reflecting import prices and TL/USD parity). Later, BOTAS

was exempted from the mechanism, and began charging subsidized prices to distribution

companies and eligible customers, while power plants under BOO and TOR contracts

remained unsubsidized.

Pricing (wholesale companies): Wholesale prices are freely negotiated between the buyer

and seller. Nevertheless, BOTAS’ tariff is used as a benchmark in the pricing process.

Such a market situation illustrated that BOTAS’ pricing policy caused a distortion of

competition, and has also affected its financial position.

3.1.2 Coal

In 2013, installed power plant capacity dependent on coal was 12,606 MW, equivalent to 20%

of total installed capacity. Capacity using hard coal and imported coal was 4,383 MW, while

capacity using lignite was 8,223 MW (Table 5). The only location in Turkey where hard coal

is extracted is the Zonguldak basin (Figure 8). Hard coal resources in the basin are estimated

at some 1,314 million tonnes. Although there are no legal restrictions on private sector

involvement, the state-owned Turkish Hard Coal Enterprise (TTK) has a de facto monopoly

in the production, processing and distribution of hard coal (EUROCOAL, 2015).

34

Figure 8. Lignite and hard coal rich regions in Turkey

Source: EUROCOAL, 2015.

Turkey mainly produces lignite, which is its most important indigenous energy resource.

Turkey’s lignite fields are spread across all regions of the country, with approximately 46% of

reserves being located in the Afsin-Elbistan basin (EUROCOAL, 2015; MENR, 2014).

Domestically produced lignite accounts for approximately 75% of the country’s coal supply

(Figure 9).

Figure 9. Production, consumption and import of coal in Turkey, 2005-2012

Source: U.S. Energy Information Administration, International Energy Outlook 2013 with projections to 2040,

2014.

3.1.3 Hydroelectric power

Turkey’s hydroelectric power sources are the most important among its renewable energy

potentials. According to MENR, total economic hydroelectric power potential in Turkey is

140 billion kWh/year, while currently 35% of that potential is utilized. In 2013, total installed

hydroelectric power capacity was 22,289 MW (Table 5), with a total of 467 hydroelectric

power plants (HEPPs). In the same year, 25% of total electricity production was generated

from hydro sources (Figure 6).

Most of the country’s economically feasible hydroelectric power potential is distributed to 14

river basins. The most important is the Euphrates River, which accounts for 30% of county’s

0

20000

40000

60000

80000

100000

120000

2005 2006 2007 2008 2009 2010 2011 2012

Th

ou

san

d S

ho

rt

To

ns Consumption

Production

Import

35

hydroelectric power potential and is where Turkey’s largest HEPPs were constructed: Ataturk

(power of 2,400 MW), Karakaya (power of 1,800 MW) and Keban (power of 1,330 MW).

There is also considerable potential in the Black Sea region, where 20% of total projects in

Turkey were developed by the private sector (Baris & Kucukali, 2012, p. 381).

In the future, an increase in the number of HEPPs would contribute to reducing Turkey’s

dependence on foreign sources of energy. Nevertheless, Turkey also faces a challenging

problem in this area, i.e. maximizing the utilization of hydroelectric power while maintaining

environmental consciousness and sustainable development. The EML (2001) provided for the

planning and construction of small HEPPs by the private sector. Consequently, this created a

market for companies that draft feasibility reports, for construction companies and for the

owners/managers of small HEPPs. Their inadequate water resource management strategies

led to the disruption of the natural flows of rivers, since their aim was to generate electricity,

with little heed paid to components of the ecosystem and the needs of local residents (Kentel

& Alp, 2013, p. 34). In 2008, a regulation was issued concerning HEPPs with installed

capacity of between 0.5 and 25 MW. The regulation instructs such HEPPs to draw up an

Environmental Impact Assessment (EIA) report if they want to obtain a small HEPP license.

Nevertheless, this regulation did not have the intended effect, since many of the licenses for

small HEPP were granted prior the entry into force of the regulation (Baris & Kucukali, 2012,

p. 382).

Despite the challenges, installed hydroelectric power capacities have developed over the last

decade. In 2006, installed hydroelectric power capacity totalled 13.1 GW, while that number

reached 22.3 GW in 2013. Turkey’s long-term target is to have 180 GW of installed

hydroelectric power capacity by 2030 (Figure 13).

3.1.4 Renewables

As already mentioned above, Turkey is heavily dependent on expensive imported energy, in

terms of electricity generation, mainly in the form of natural gas and high-quality coal. Its

main domestic energy resources are coal (lignite) and hydroelectric power.

Turkey’s advantageous geographical location provides for the possible use of several

renewable energy sources. The first major source is hydroelectric power, which was presented

in the previous subchapter. The other potential renewable energy sources are solar, thermal,

wind, geothermal and photovoltaic energy (Yuksel, 2013, p. 1038). In terms of renewable

energy sources, 25% of electricity is currently generated from hydropower (59,421 GWh), 1%

from geothermal sources (1,364 GWh) and 3% from wind (7,557 GWh), while the remainder

(71%) is produced from fossil fuels (Figure 5).

In addition to dependency on imports of fossil fuels, which affects the country’s current

account deficit and price stability, air pollution also gives rise to severe environmental issues

in Turkey as the result of increasing energy consumption. Turkey is addressing these issues in

parallel with the need to comply with the Kyoto protocol and EU Directives (Bölük, 2013, p.

153).

36

The main instruments that promote renewable energy use in the EU are purchase guarantees

by feed-in-tariffs, quota applications and energy tax exemptions. Meanwhile, in Turkey, the

first instrument was the EML, which allows individuals and small corporate entities to build

electricity generation facilities with a maximum installed capacity of 500 KW from renewable

energy sources that are exempt from licensing obligations (Baris & Kucukali, 2012, p. 385).

With the new EML, maximum installed capacity has been raised to 1 MW, while the Council

of Ministers is authorized to increase that level to 5 MW. The second instrument was the Law

on the Utilization of Renewable Energy Sources for Electricity Generation (No. 5346, Official

Gazette, No. 25819). Under the aforementioned law, several mechanisms were developed in

Turkey to support the use of renewable sources (Baris & Kucukali, 2012, p. 386; Atiyas et al.,

2012, p. 120):

a) Licensing: In addition to a license exemption for a maximum of 1 MW of installed

capacities (from renewable sources) for those who do require a license, only 1% of the

licensing cost is paid by the applying entity, which is exempt from annual licensing costs

for the first eight years.

b) Land appropriation: Real properties that are deemed forest or the private property of the

Treasury receive the right of easement, usage permits or are leased. Moreover, an 85%

discount is applied to rent, the right of easement and usage permits, while several costs are

not charged for the first ten years.

c) Purchase guarantees: Government guarantees to buy electricity offering a feed-in-tariff of

5-5.5 €c/kWh for utilities that are less than 10 years old.

Law No. 5346 was amended in 2010 by the Law Amending the Law on the Utilization of

Renewable Energy Sources for Electricity Generation (No. 6094). One major change related

to feed-in-tariffs, which were deemed very low. Although much higher feed-in-tariffs were

proposed in 2009, the following were confirmed in the framework of Law No. 6094. The new

tariffs are applicable to plants built or to be built between 18 May 2005 and 31 December

2015, offering an amount of 5.6 €c/kWh for hydropower and wind, 8 €c/kWh for geothermal,

and 10.2 €c/kWh for solar and biomass power plants. Moreover, the domestic manufacturing

of equipment used is promoted via feed-in-tariffs ranging from 0.3 to 2.7 €c/kWh (Atiyas et

al., 2012, pp. 113-123).

A comparison of Turkey’s feed-in-tariffs and those of selected EU Member States is shown in

Appendix D. As discussed by Baris & Kucukali (2012, p. 385), Turkey’s mechanisms are

deemed to be inadequate compared with leading EU countries in the utilization of renewable

energy sources. On the other hand, taking into account the opinion of Atiyas (et al., 2012, p.

123) with regard to the difficulties faced by Spain, Germany and Italy, which are considered

the highest feed-in-tariffs countries since the financial crisis of 2008, Turkish tariffs may

actually be reasonable in terms of long-term stability.

The current utilization of renewable sources in Turkey is analysed below.

Wind energy

Data show that 2,760 MW of wind capacity was installed in Turkey in 2013 (Table 5).

Installed wind capacity is expected to grow at a rate of between 500 and 1,000 MW per year

37

to reach more than 5 GW by 2015, while the country’s goal is to install up to 20 GW by 2023.

For this ambitious target to be reached, the transmission structure will have to be upgraded in

the future in order to allow such large scale development to be connected to the power grid

(Toklu, 2013, p. 462).

According to MENR (2014), wind energy potential in Turkey is estimated to be 48,000 MW.

Plants with a capacity of 5 MW can be built in Turkey in areas with a wind speed exceeding

7.5 m/s. Also, as noted in Figure 11, the country is aiming to achieve 40 GW of installed wind

capacity by 2030.

Geothermal energy

With its location on the Alpine-Himalayan belt, Turkey has a high geothermal potential. It has

been estimated that 2,000 MW of electricity can potentially be generated via geothermal

energy. Current data indicate a total of 706.4 MW of potential capacities for which licenses

were obtained from EMRA. Nevertheless, current installed capacity is 404.9 MW, generated

by 15 geothermal power plants (MENR, 2014).

Other potential renewable sources

Turkey is suitable for the use of solar energy, with gross solar potential calculated at 117 GW

per year, 40% of which can be used economically (Toklu, 2013, p. 461). There are currently

some small-scale photovoltaic solar energy systems in the country that were established

primarily for research purposes. MENR is planning to install 3,000 MW of photovoltaic

power plants in 2023 in several stages. Licenses for 600 MW will be issued in the first phase,

followed by an increase in capacity to reach the 2023 target (MENR, 2014).

Bioenergy potential, which covers biodiesel, bioethanol, biogas and biomass, is also

important for Turkey. Biomass has an annual potential of 42 GW, while 10 GW was actually

produced from biomass in 2010. A projection for 2030 indicates that the aforementioned

number will increase to 11 GW (Baris & Kucukali, 2012, p. 384).

38

2006 2007 2008 2009 2010 2011 2012 2013

THERMAL 27.4 27.3 27.6 29.3 32.3 33.9 35.0 38.6

HYDRO 13.1 13.4 13.8 14.6 15.8 17.1 19.6 22.3

GEOTHERMAL 0.1 0.2 0.0 0.1 0.1 0.1 0.2 0.3

WIND 0.0 0.0 0.4 0.8 1.3 1.7 2.3 2.8

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

40.0

45.0

Insta

lled

ca

pa

cit

y (

GW

)

2030 Renewables Target (GW)Hydropower: 180.0Wind energy : 40.0Geothermal: 4.2Solar energy : 10.0Biomass : 2.2

Figure 10. Turkey’s installed renewable capacity and thermal capacity 2006-2013

Source: Electricity generation & transmission statistics of Turkey for year 2013; I. Yuksel, Renewable energy

status of electricity generation and future prospect hydropower in Turkey 2013, 2013, p. 1040.

3.2 Transmission

Transmission activities are performed by the state-owned TEIAS, which has a complete

monopoly over this segment of the electricity market due to the natural monopolistic

characteristics of the transmission infrastructure. TEIAS works under a transmission license

and is responsible for all transmission facilities in the country. It also plans load dispatch and

operational services (TEIAS, 2014). As stated in the 2013 TEIAS statistical report (2013),

Turkey has 51,344 km of transmission lines with several projects in progress. The current

lengths of the transmission lines at 380 kV (also referred to as 400 kV), 220 kV, 154 kV and

66 kV voltages are 16,808 km, 84.5 km, 33,942.5 km and 509.4 km respectively (Appendix

E).

Turkey is currently interconnected with Greece, Bulgaria, Georgia, Iran, Iraq and Syria. One

of the most important interconnections for the country in terms of commercial exchange is the

ENTSO-E connection with Greece and Bulgaria. There are two 400 kV transmission lines on

the Turkey-Bulgaria interconnection (one 145 km long and the other 136 km long), while

there is a 130 km long 400 kV transmission line on the Greece-Turkey interconnection

(Figure 11).

Figure 11. Turkey’s interconnection with neighbouring countries

BULGARIA

145 km 400kV

136 km 400kV

GEORGIA

28 km 220kV (Hopa-Batumi)

160 km 400kV (Borcka-Akhaltsikhe)

39

Source: F. Kölmek, Turkish Power Balancing Market 2014; 2014; Deloitte Consulting, Turkey import and

export expectations – project report 2, 2013.

Following several stand-alone operational tests, the Turkish system was synchronously

connected to Continental Europe in September 2010. A test of the parallel synchronous

interconnection was subsequently planned. However, due to technical problems within the

Turkish network, trial operations were extended in order to achieve satisfactory compliance

with Continental European rules by TEIAS. In June 2011, limited commercial exchanges

were successfully performed on the interconnection. Moreover, the capacity available for

trade has been gradually increasing, and is currently 550 MW for imports to Turkey and 412

MW for exports from Turkey (Staschus, 2014, p. 41). The long-term plan is to reach 1,200

MW on the both the import and export side, as well as a permanent synchronous connection

with Continental Europe.

The first commercial exchange with Greece and Bulgaria in 2011 resulted in two changes in

overall Turkish cross-border electricity exchange activities. The first was an increase in total

electricity imports from 2,288 GWh in 2010 to 9,112 GWh in 2011 (an increase of 300%),

and an increase in electricity exports from 3,635 GWh in 2010 to 7,289 GWh in 2011.

Secondly, Turkey became a net electricity importer, while it was a net electricity exporter

prior to the ENTSO-E connection. In 2013, imports reached 14,858 GWh, with 64% of

electricity imported from Greece and Bulgaria. On the other side, exports during the same

year were much lower than in 2011 or 2012, reaching 2,453 GWh, with 64% of electricity

exported to Continental Europe (Figure 12).

TURKEY

SYRIA

124 km 400kV

GREECE

130 km 400kV IRAQ

NACHIVAN-AZERBAIJAN

87 km 154kV

IRAN

73 km 154kV

100 km 400kV

ARMENIA

80.7 km 154kV

412 MW

550 MW

15-80 MW

0 MW

40 MW

40 MW

150 MW

380 MW

400 kV Existing

400 kV Under construction

220 kV Existing

154 kV Existing

700 MW

40

Figure 12. Total electricity imports and exports by Turkey 2003-2013

Source: Electricity generation & transmission statistics of Turkey for year 2013, 2013.

The available transmission capacity (ATC) on both borders is allocated via the explicit

auction method. Market participants can submit their bids for capacity via an auction platform

and, if the volume of offered capacity is higher than the volume of required capacity, the

auction price is €0/MWh. In the opposite case, when congestion occurs, capacity is payable.

Capacity auctions are conducted by each country’s TSO. A total of 50% of interconnection

capacity is auctioned by TEIAS, 32.5% by the Bulgarian TSO (ESO) and 17.5% by the Greek

TSO (HTSO) (Deloitte Consulting, 2013, p. 12).

Another important interconnection is Georgia-Turkey. Turkey is interested in increasing

electricity trade with Georgia, particularly because of Georgia’s rich renewable energy

sources, and also because of the Turkey’s increasing electricity demand (Deloitte Consulting,

2014, p. 2). Interconnection comprises two lines: the first is the Hopa (Turkey)-Batumi

(Georgia), 28 km-long 220 kV transmission line. The second is the Borcka (Turkey)-

Akhaltsikhe (Georgia) 400 kV transmission line, which is 160 km long (Figure 12). There is

no possibility of synchronous parallel operation between the two countries on this

interconnection, since Georgia is not an ENTSO-E member. Two different methods are

currently applied on the Hopa-Batumi line (Deloitte Consulting, 2013, p. 18, Electricity

Market Import and Export Regulation, Official Gazette, No. 29003):

a) Directed unit method: Operation of a generation facility or a unit of a generation facility

in the electricity system of the country that electricity is to be imported from/exported to,

0

2000

4000

6000

8000

10000

12000

14000

16000

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

GW

h

Imports Exports

41

in parallel with the national electricity system. No capacity was allocated under this

method in 2014.

b) Isolated region method: An isolated region is formed in the country that electricity is to be

exported to via interconnection lines. In October 2013, EMRA amended the license issued

to the private company that holds the right to export on this line. However, the company

declared it will start exporting after May 2015. On the other hand, TETAS cannot export

energy at present, since its energy trade agreement has not yet been renewed.

For the Borcka (Turkey)-Akhaltsikhe (Georgia) line, the asynchronous parallel operation

method will apply. The interconnection has been constructed and tests completed. There was

610 MW of capacity available for electricity transmission in December 2014. As a rule

between the countries, the exporting country determines to whom the ATC will be allocated,

in this case Georgia as it is in the position of exporter. (Deloitte Consulting, 2014). Georgia

does not have a day-ahead electricity market and no auction platform. Auctions for the ATC

are therefore oral.

With regard to other neighbouring countries, the Iran-Turkey line (600 MW) back-to-back

station is expected to be completed by 2016. In addition, reinforcement of the Iraq-Turkey

interconnection line continues, while trade is currently possible via the isolated region

method. There is no trade on the Syria-Turkey border.

3.3 Wholesale market

The Turkish electricity market is still in the process of restructuring. Consequently, its current

wholesale market structure has not yet shifted to the final phase. Nevertheless, the final

market structure proposed under electricity regulations is in line with the EU Internal Energy

Market. Figure 13 illustrates the current wholesale electricity market structure in Turkey. It

can be noted that the market is based on a bilateral contracts market complemented by a

balancing mechanism. An analysis of each segment of the wholesale market will be presented

in the following subchapters (Deloitte Consulting, 2012, p. 8).

As a tradable commodity, electricity is unusual in that it cannot be easily stored. The

maximum capacity of all electricity-producing plants in a region determines the maximum

supply of electricity in that region at a given moment. For a certain region (the so-called

control area), demand and supply are first matched. Any excess power may then be sold to

other control areas. This excess power constitutes the wholesale electricity market (Hull,

2009, p. 584). Electricity can be traded either physically or financially. Physical trading refers

to a situation when the electricity traded is actually produced and delivered, while the purpose

of financial trading is to hedge against price volatility (physical delivery does not occur)

(Verdugo Penados, 2008, p. 14). In Turkey, most electricity trade is physical, while the

financial markets are expected to develop additionaly with novelties in the market, which are

explained in Subchapter 3.3.6.

Figure 13. Current structure of the wholesale electricity market

42

Bilateral contract Balancing mechanism

More than 1 year 1 year

Source: Deloitte Consulting, Turkish electricity market review, 2012, pp. 9-10.

3.3.1 Bilateral contracts and the role of TETAS

The majority of Turkish electricity contracts in place are between a generation company or a

wholesale company and a distribution12

company or an end-customer (bilateral energy sales

contracts). Bilateral contracts are not standardized. European Federation of Energy Traders

(EFET) standard contracts are therefore not commonly used. Consequently, the form and

terms are subject to negotiations between parties, and EMRA has no supervisory power over

these contracts. On the other hand, in contrast to private sector wholesale companies, all

public contracts of TETAS are subject to EMRA’s approval (Ergün & Gökmen, 2013, p. 17).

Figure 15 illustrates the bilateral contracts system of Turkey, and its energy flow.

Specifically, three types of bilateral contracts exist on the market (Deloitte Consulting, 2012,

p. 10; TETAS, 2013, pp. 20-22):

a) Long-term contracts between BOO/BOT/TOR and TETAS. These private sector power

plants have contracts with TETAS, starting from 1989, and are valid for a period of

between 15 and 30 years.

b) Transition period contracts (TPCs) between EUAS, TETAS and distribution companies.

The energy flow goes from EUAS to TETAS, and the electricity is delivered to the non-

eligible customers of 20 distribution companies. Currently, they operate separately on the

market; distribution activities are performed under a distribution license, while retail

activities are performed under a supply license (Figure 14). In 2006, an agreement was

12

Before unbundling, distribution companies also performed retail activities on the market. Since 2013,

distribution companies operate under a distribution license (they maintain the distribution network), while

electricity is sold to customers by retail companies under a supply license.

Plant

investment

Fuel

agreement

Maintenance

plan

Fuel supply

Supply and demand

planning

Operating

reserves

planning

Day-ahead

balancing and

optimization

Bilateral contracts and financial

markets Day-ahead market Balancing power

market

Ancillary services

1 day-ahead 15-1 minutes 8-6 hours

Real

time

Bilateral: Contracts between

BOO/BOT/TOR plants and TETAS,

and freely negotiated contracts

between market participants and

between market participants and

eligible customers.

Financial markets: Borsa Istanbul

Operated by market

operator (PMUM,

department within

TEIAS); hourly

settlement.

Operated by transmission system operator (MYTM,

department within TEIAS).

43

made (a transition period contract) under which TETAS purchased 20-23 billion kWh of

electricity from EUAS on an annual basis. The agreement was valid until the end of 2012.

However, in 2013, new agreements were concluded, and 68,614,230,100 kWh of

electricity energy was purchased from EUAS by TETAS.

c) Freely negotiated contracts between market participants and eligible customers.

Figure 14. Bilateral contracts electricity market and energy flow

Source: Deloitte Consulting, Turkish electricity market review, 2012, p. 11.

State-owned TETAS plays an important role in the wholesale trading system as it was

established in the scope of electricity market reform to carry out wholesale trading and

contracting activities. TETAS therefore purchases electricity from EUAS, BO/BOT/TOR

plants, other countries (based on import contracts) and the balancing market. It sells energy to

electricity distribution companies, electricity retail sales companies, customers connected to

the transmission system, other countries (under export contracts) and the balancing market

(TETAS, 2013, p. 16).

Generation

Transmission Wholesale Distribution Retail

EUAS HEPP

BOO/BOT/TOR

EUAS

PORTFOLIOS

TETAS

TRANSMISSION

CONNECTED

ELIGIBLE

CUSTOMERS

KAYSERI distrib.

company

TEDAS/ NON-

ELIGIBLE

CUSTOMERS (20

distrib. companies)

EXPORT/IMPORT

PRIVATE

PRODUCERS

PRIVATE

WHOLESALE

COMPANIES

ELIGIBLE

CUSTOMERS

EXPORT/IMPORT

Transition contracts

Long-term agreements

Bilateral contracts

44

2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

ELECTRICITY PURCHASED FROM

PRODUCTION COMPANIES82 81 80 80 69 47 44 43 41 36 35 55

IMPORT OF ELECTRICITY 100 100 100 100 100 100 100 100 81 9 5 4

EXPORT OF ELECTRICITY 100 68 33 23 25 50 14 21 33 0.5 0.9 0.01

SALES OF ELECTRICITY 77 77 78 78 68 46 43 43 41 35 34 53

0

20

40

60

80

100

120

Sh

are

of

TE

TA

S

Market share of TETAS 2002-2013

Table 8. TETAS trading portfolio in 2013 (purchase)

Source: TETAS, 2013 Annual Activity Report, 2013, p. 33.

In is evident from the TETAS trading portfolio in 2013 (Table 8) that 98% of electricity

purchased in 2013 by TETAS was based on either TPCs or BOO/BOT/TOR contracts.

According to a TETAS report (2013, p. 33), a major portion of purchased electricity was sold

to retail or distribution companies, while a smaller portion was sold either directly to eligible

customers, on the market (PMUM) or was exported.

Figure 15. Market share of TETAS 2002-2013, in percentages

Source: TETAS, 2013 Annual Activity Report, 2013, p. 34.

Since TETAS was expected to help the Turkish electricity market to transition smoothly to a

competitive structure, the company retained around 75% of national electricity trade between

2002 and 2006. Despite the enforcement of transition period contracts in 2006, its market

share had declined to 35% by 2012 (Karahan in Toptas, 2013, p. 617). In 2013, its market

share of national electricity trade exceeded 50%, probably due to additional contracts with

Electricity purchased from Quantity (GWh) Percentage

EUAS 68,614 52.3

BOO 42,939 32.8

BOT 13,293 10.1

TOR 3,715 2.8

PMUM (MFSC) 2,242 1.8

IMPORT 227 0.2

TOTAL 131,079 100

45

EUAS. In terms of international electricity trade, its market share has fallen significantly due

to reform efforts and also due to the possibility given to all the market participants to obtain

cross-border transmission capacities. Moreover, only 4% of electricity imports were carried

out by TETAS in 2013 and 0% of exports. The remainder of international trade is carried out

by wholesale traders. It is expected that TETAS will operate with lower market shares in the

sector in the coming years (Figure 15).

The majority of the Turkish wholesale electricity market comprises bilateral contracts. As

seen in Figure 16, bilateral contracts accounted for 75% of market volume on a selected date

in October 2014. A total of 21% of the electricity was traded on the organized day-ahead

market, while a small proportion (4%) was traded via the balancing market. The public and

private sectors accounted for 67% and 33% of the bilateral contracts market respectively.

Figure 16. Proportion of the Turkish wholesale electricity market accounted for by bilateral

contracts, and bilateral contracts by sector (on 9 October 2014), in percentages

Source: PMUM – General Reports, 2014.

Figure 17 shows the increasing proportion of private bilateral contracts on the market in the

period 2011 to 2014. On the other hand, public bilateral contracts dominate the market, with

the number of public bilateral contracts in 2014 exceeding the number in 2011. It is a fact that

public-sector presence is high on the market, where TETAS plays an important role.

Figure 17. Private and bilateral contracts

0,00

5.000.000,00

10.000.000,00

15.000.000,00

20.000.000,00

dec

.11

feb.1

2

apr.

12

jun

.12

avg.1

2

okt.

12

dec

.12

feb.1

3

apr.

13

jun

.13

avg.1

3

okt.

13

dec

.13

feb.1

4

apr.

14

jun

.14

avg.1

4

Public B.C.

Private

B.C.

46

Source: PMUM – General Reports, 2014.

3.3.2 Derivatives

Electricity can also be traded financially with the aim of hedging against price volatility. In

such cases, physical delivery does not occur. Derivatives traded via the organized market in

Turkey are referred to as future power contracts or “base load electricity futures”.

Power futures have been traded on the Turkish Derivatives Exchange (TurkDex) since trading

started on 26 September 2011. In 2013, trading was transferred to the Borsa Istanbul Futures

and Options Market. Power futures represent a small proportion of the total market volume. In

2012, for example, the total traded volume of all contracts on the TurkDex was 62 million,

with a total value of $200 billion. In the same year, electricity futures recorded a volume of

928 contacts or 0.0015% of total traded volume (Borsa Istanbul, 2013). The value of those

928 contracts was $9.5 million.

Figure 18. Volume and value of base load electricity futures (2011–2013)

Source: Borsa Istanbul, Borsa Istanbul and the Energy Market, 2013, p. 13.

The reference price for base load electricity futures is the average of the day-ahead hourly

prices of the maturity month obtained from TEIAS (Borsa Istanbul – Base load electricity

futures, 2015). In practice, these contracts do not attract much interest. It seems that investors

believe that prices on the day-ahead market do not reflect the real supply-demand balance.

The main reason is the large proportion of state-owned utilities in power generation, and the

fact that natural gas market prices are regulated (Bademli, 2013). The low volumes of

electricity futures can be seen in Figure 18.

Developed markets, such as Germany with one of the leading energy exchanges in Europe

(EEX), have much higher trading volumes for comparable products. At least 200 electricity

futures contracts are traded in a single day on the EEX (EEX, 2014).

3.3.3 Day-ahead market

47

The Turkish day-ahead electricity market began functioning on 1 December 2011. It is “an

organized wholesale electricity market for the purchase and sale of electricity to be delivered

in the day-ahead timeframe on the basis of a settlement period” (hourly) (Camdan & Kolmek,

2013, p. 63). The day-ahead market is operated by the market operator, Electricity Market

Financial Settlement Centre – MFSC (Piyasa Mali Uzlas¸ tırma Merkezi – PMUM). MFSC is

a part of the state-owned TEIAS (a department within TEIAS). The law laying down

principles and procedures on the day-ahead market is the Electricity Market Balancing and

Settlement Regulation drafted by EMRA.

Daily bids and offers are submitted to the market on a portfolio basis. Participants submit

their price-volume pairs, with the responsibility to balance their whole portfolio. Both the

supply and demand sides may compete on the market, with producers on one side and

wholesale or retail companies on the other (Deloitte Consulting, 2012, p. 12).

Participants may submit their offers/bids in three different ways (Electricity Market Balancing

and Settlement Regulation, 2009, pp. 33-34; Deloitte Consulting, 2012, p. 15):

a) Single hour purchase or sales

Market participants submit a bid (price-quantity pair) for each hour of the following day

(maximum of 32 different price levels for each purchase and sale). Bid quantities are

submitted in lots representing 0,1 MW and its folds, while the minimum price limit is “0

TL/MWh” and the maximum limit is “2,000 TL/MWh”.

b) Block purchase

The term “block” refers to a constant purchase/sales volume, in terms of hourly MWh, that a

market participant is willing to buy/sell for a certain time interval. Market participants are

able to offer their customized block bids/offers or to bid/offer a predefined period of time

determined by the system operator. The blocks span at least four hours, and participants are

allowed to submit at least 50 block bids/offers in a day. For example, a trader may submit a

bid covering the hours 2 am to 8 am (block) to purchase 100 MWh at a price of 100

TL/MWh.

c) Flexible sales

These are single hour sales bids that are not associated with a certain hour, and differ from

single hour purchase and sales bids. Flexible sales are used by producers, since they allow

them to utilize their flexible generation capacity (for example hydro power plants). Bids and

offers are submitted in such a way that the technical aspect of the plant is considered, as well

as marginal costs for the portfolio. A producer may submit an offer when it is economical to

generate at that price, or it may submit a bid when it is more economical to purchase from the

market (instead of generating itself). For example, a producer has three power plants in a

portfolio with a total capacity 130 MW, and signed bilateral contracts for 80 MW (Table 9).

Table 9. Generation company X’s portfolio

Capacity Marginal Cost (TL/MWh)

48

Source: Deloitte Consulting, Turkish electricity market review, 2012, p. 15.

Considering its marginal costs, it is economical for it to generate the 80 MW when the price

on the market is higher than 60 TL/MWh. On the other hand, when the price is 0 TL/MWh, it

is more economical to buy the 80 MW on the market. Table 10 shows its bids/offers on the

market, which are flexible according to the producer’s portfolio.

Table 10. Example of flexible sales/bids of generation company X

Note: 1 MW = 10 LOT

Source: Deloitte Consulting, Turkish electricity market review, 2012, p. 15.

As Table 10 shows, generation company X may sell 50 MW when the price is higher than 90

TL/MWh. It produces the contracted 80 MW at a lower price, and then it uses its remaining

capacity to sell it on the market, since its marginal costs are lower than the market price.

3.3.4 Balancing market

The balancing market is operated by the system operator, the National Load Dispatch Centre

– NLDC (Milli Yük Tevzi Merkezi, MYTM). NLDC is a part of state-owned TEIAS (a

department within TEIAS).

The balancing market is needed to maintain physical supply and demand equilibrium.

Although the system is theoretically in balance after the day-ahead market is closed, market

participants may produce below or above their daily accepted bids/offers for different reasons,

leading to imbalances in real time. However, in such cases, flexible producers who can load

or reload the system on short notice to balance the system are able to submit their bids/offers

through a transparent market application, the so-called balancing market (Deloitte Consulting,

2012, p. 19).

Market participants who are able to participate on the market are those who are regarded as

balancing entities, meaning that they can independently load or reload the system with 15

minutes’ notice. Such entities are gas-fired plants and hydro storage plants, since they have

the requisite generation flexibility. Unfortunately, producers who use renewable sources do

not have the flexibility required, but are still required to participate on the balancing market,

via their finalized daily generation schedules, instead of submitting bids/offers (Deloitte

Consulting, 2012, p. 19).

Power plant 1-60 MW 60

Power plant 2-40 MW 80

Power plant 3-30 MW 90

TOTAL : 130 MW *Signed contract with its customer for six months (for 80 MW)

Price

(TL/MWh)

0 40 60 70 80 90 100 110

Participant

(LOT)

800 800 200 200 0 -500 -500 -500

49

3.3.5 Price determination and market data

The price on the day-ahead market is determined at the intersection of supply and demand.

For each trading hour, a supply curve is formulated from a combination of price-quantity

pairs that are listed in ascending order and combined into one offer. The demand curve is

formulated in the same manner, but the pairs are listed in descending order. The intersection

of the supply-demand curves determines the price of the relevant hour, the so-called market

clearing price (MCP) (Figure 19 – left).

Figure 19. Price determination on the day-ahead market (left) and balancing market (right)

Source: F. Kölmek, Turkish Power Balancing Market, 2014; Deloitte Consulting, Turkish electricity market

review, 2012, p. 17.

The price of the balancing market depends on whether there is an energy deficit or energy

surplus in the system. First, all offers/bids submitted to the balancing market are ranked

according to their prices. If there is an energy deficit in the system, the maximum accepted

hourly offer price in the system is accepted as the system marginal price (SMP). This situation

where a balancing entity sells energy to the system is called up-regulation. On the other hand,

when there is a surplus, the minimum accepted bid price is accepted as the SMP. The situation

where an entity buys energy from the system in order to correct an imbalance is referred to as

down-regulation (Electricity Market Balancing and Settlement Regulation, 2009, pp. 6-7).

Figure 19 (right) gives an example where there was an energy deficit in the system, and the

SMP was higher than the MCP for the relevant hour after up-regulation instructions.

The wholesale electricity price is influenced by several factors, since electricity cannot be

stored and is always produced at the exact moment of demand. Supply and demand drivers

therefore have an immediate impact on spot prices. Consequently, the electricity price

formulated for the following day is subject to many fluctuations. The main factors affecting

the supply side are fuel prices (for coal, gas and oil) and the prices for CO2 allowances. For

power plants using renewable sources, wind and weather are very important as they determine

the quantity of generated electricity. In addition, on the supply side, the capacities of power

plants, their current technical condition and planned or unplanned outages have an effect on

the price. Weather also plays an important rule on the demand side. Customer behaviour is

0

40

80

120

160

200

-30 10 50 90 130 170 210 250

TL

/MW

h

MW

Day-ahead market

Demand Supply

60 MW

MCP = 90 TL/MWh

0

20

40

60

80

100

120

-30 20 70 120 170 220

TL

/MW

h

MW

Balancing market

Supply Demand

120 MW

SMP= 95 TL/MWh

50

directly influenced by the temperature and cloud cover. Other demand side price drivers are

major public or school holidays. Another important factor is the global economy. For

example, demand fell due to the economic crisis, resulting in a drop in electricity prices

(RWE – Press and News, 2015).

Based on all relevant findings regarding the Turkish electricity market, the main electricity

wholesale price drivers in Turkey are as follows:

High generation costs: A large proportion of electricity is produced from natural gas. The

supply of natural gas is tied to expensive import contracts. In addition, the BOTAS pricing

system distorted competition on the market, since there is no competitive pricing on the

natural gas market.

High electricity demand driven by industrialization and urbanization.

Weather: Demand is higher in the summer due to hot weather and the usage of cooling

devices. A similar situation occurs during the cold winter months, when the usage of

heating devices increases.

Islamic holidays: The most important holiday is Kurban Bayram. Electricity consumption

is expected to be very low on this day, resulting in low wholesale prices.

Political influence: The high market share of state-owned companies distorts competition.

High system losses, especially distribution losses (explained in Subchapter 3.4.).

Figure 20 illustrates the development of the Turkish wholesale electricity market price. Peaks

are noted during the coldest winter months or on the hottest summer days, probably due to the

increased demand arising from increased usage of heating or cooling devices. Turkey’s

average prices are higher than those of the CEE region. For example, the average CEE

wholesale price in February 2012 was €62/MWh compared with €73/MWh in Turkey. Later,

in June 2013, CEE prices fluctuated at around €30/MWh, which is much lower than in Turkey

where the price was €55/MWh (Figure 22). According to EC quarterly reports (DG Energy –

Market Observatory for Energy, 2013), the CEE region is the most dynamic power trading

region in Europe. The reason for its low prices in 2013 lies in the limited industrial demand

for electricity, which was impacted by the sluggish economic recovery, decreasing generation

costs (cheap coal imports and low carbon prices) and abundant renewable supply in Germany.

Figure 20. Turkish wholesale electricity market price

51

Source: PMUM – General Reports, 2014.

On the other hand, if we compare Turkish prices to the SEE region, more specifically to

Greek electricity prices, some similarities are seen in the dynamics of the price curve,

although the peaks in 2012 are higher and prices were lower in Greece in 2013. In April 2013,

electricity production and consumption were close to their lowest levels in decades in Greece

due to the economic situation and weather conditions in that country (DG Energy – Market

Observatory for Energy, 2013).

Figure 21. Wholesale electricity market prices of the EU REM (Q2 2013)

Source: DG Energy – Market Observatory for Energy, Quarterly Report on European Electricity Markets,

second quarter 2013, 2014, p. 10.

3.3.6 Expected future market developments

52

The new EML stimulates and accelerates the process of establishing a competitive and fully

liberalized market. There are several market changes and developments expected in the near

future.

The wholesale market will be operated by three market operators, namely the newly

established EPIAS (which holds a market operation license), which will cover the day-ahead

and intra-day markets, while the Borsa Istanbul will be responsible for standardized electricity

contracts and derivatives markets. The balancing power market and ancillary services market

will continue to be operated by TEIAS. Moreover, spot transactions and derivatives will be

under one exchange (Boden Law Company, 2013, p. 2). In addition, EPIAS will cover

financial settlement obligations for the markets operated by TEIAS and EPIAS.

EPIAS was established as a joint-stock company at the beginning of 2015, with total capital

of 61,572,779 Turkish liras (approximately €21 million). A total of 30% of shares were

bought by TEIAS (Type-A shares) and BOTAS equally, while 30% of shares were bought by

the Istanbul Stock Exchange (Type-B shares). The remaining 40% of shares (Type-C shares)

were bought by private energy companies. The main agreements are currently being signed.

Following the registration of shares, EPIAS will be able to start with its first transactions

(Herdem, 2015).

Table 11 shows the difference between the old and new market structure.

Table 11. Comparison of the current and new wholesale electricity market structure

Source: Own

Market Current structure New EML structure

Wholesale market organization Hybrid: bilateral contracts,

day-ahead and balancing

market covered by TEIAS

(MFSC; NLDC); derivatives on

Borsa Istanbul.

EPIAS covering day-ahead

(including bilateral contracts)

and intraday exchange, TEIAS

covering balancing market and

Borsa Istanbul operating the

derivatives market. Clearing

house is Taksabank.

Market operators TEIAS (MFSC and NLDC),

Borsa Istanbul.

EPIAS, TEIAS and Borsa

Istanbul.

OTC markets Not defined by the EML,

energy transactions under

bilateral contracts.

Also not defined by the new

EML.

Licensing Generation, transmission, retail

sales, distribution,

autoproducer and autoproducer

group license.

Preliminary license, generation

license, supply license, market

operation license, autoproducer

license.

53

Although the new EML brings positive changes for the organized wholesale market, OTC

markets have been left out. The aforementioned law excludes OTC markets from the

definition of wholesale markets. Electricity trading is recognized based on bilateral contracts,

as it was under the 2001 EML (Boden Law, 2013, p. 2). Moreover, all contracts relating to the

organized wholesale markets are exempt from the stamp tax duty. Because OTC markets are

not defined by the EML, they cannot benefit from that exemption (Bademli, 2013).

In addition to the aforementioned changes and updates expected in the near future, there has

already been some progress in terms of market transparency. The current platform used for

day-ahead and balancing market bids (operated by TEIAS – NLDC and MFSC) has been

upgraded. In the past, it was possible to enter bids and see the prices of the day-ahead and

balancing market, while the platform is now more transparent and offers information about:

daily reports, Outage and Maintenance Notification Reports, Congestion Cost Reports and

Market Development Reports (number of eligible customers, types of licenses and number of

market players etc.). With such information available, analysts and traders have the

opportunity to evaluate the forecasted market price better, and to understand the functioning

of the overall market (PMUM – General Reports, 2014).

3.4 Distribution and retail markets

The distribution and retail markets were explained to some extent in Chapter 2.3. To

summarize, distribution and retail activities were legally unbundled in 2013. There are 21

distribution regions in the country, while each region has its own distribution company that

was initially publicly owned and later privatized using a TOR model. There are currently 21

private distribution companies operating under distribution licenses. Nevertheless, TEDAS is

the sole owner of distribution assets. The same companies are also entitled to perform retail

activities under a separate license. The market is also open to any private company that

obtains a supply license to sell electricity to eligible customers. On the other hand,

wholesalers are also allowed to sell electricity to eligible customers.

The Turkish retail market is not yet fully liberalized. The eligible customer threshold level

was gradually decreased from its initial level of 9 GWh/year to 4,500 kWh/year in 2014. Full

opening of the market is expected by the end of 2015 (Deloitte, 2013, p. 30, Enerjisa, 2015).

The data for October 2014 shows that the number of eligible customers in Turkey exceeded

one million (Figure 22), meaning that the degree of market opening is currently 85%.

Figure 22. Retail market opening in Turkey

54

Source: PMUM – General Reports, 2014.

With the gradual opening of the market and increased cross-border trading with Continental

Europe, we can see an increase in the number of registered private-sector retail and wholesale

market participants. There are currently 42 private companies operating on the retail market

under supply licenses, and 152 companies operating on the wholesale market, likewise under

supply licenses. In terms of distribution, 21 privatized companies are operating the

distribution network under distribution licenses (PMUM – General reports, 2014).

Expectations from privately run distribution companies include a reduction in system losses

and an improvement in reliability. Turkey incurs high system losses (technical and illegal

use). According to TEIAS data, distribution losses have been historically high, from 6.9% in

1984 to the highest level of 16.8% recorded in 2000. A 13.3% distribution loss was recorded

in 2013, higher than the 12.7% loss in 2011 and 2012. In addition, transmission losses

average 2.5%, meaning that total system losses (distribution and transmission) account for an

average of 16.5% of total consumed electricity. Power outages are also common in Turkey

and affect economic activity. Interruptions are most common in eastern and south-eastern

Anatolia. With regard to illegal use, households that report no expenditure are located in

provinces with high network losses (Atiyas et al., 2012, p. 6, p. 55; Electricity generation &

transmission statistics of Turkey for year 2013).

Tariffs and prices

As stated in the Electricity Market Tariffs Regulation, transmission and distribution activities

on the market, as well as the sale of electricity or capacity or the provision of retail services to

non-eligible customers are regulated by EMRA through tariffs. There are six types of

regulated tariffs as follows (Electricity Market Tariffs Regulation, Official Gazette, No.

25929, p. 4; Atiyas et al., 2012, p. 27):

1. Transmission connection tariff: The tariff is drawn up and proposed by TEIAS.

0

200.000

400.000

600.000

800.000

1.000.000

1.200.000

12/2

00

9

02/2

01

0

04/2

01

0

06/2

01

0

08/2

01

0

10/2

01

0

12/2

01

0

02/2

01

1

04/2

01

1

06/2

01

1

08/2

01

1

10/2

01

1

12/2

01

1

02/2

01

2

04/2

01

2

06/2

01

2

08/2

01

2

10/2

01

2

12/2

01

2

02/2

01

3

04/2

01

3

06/2

01

3

08/2

01

3

10/2

01

3

12/2

01

3

02/2

01

4

04/2

01

4

06/2

01

4

08/2

01

4

10/2

01

4

October 2014:

1,056,185 eligible

customers in Turkey

55

2. Distribution connection tariff: The tariff is drawn up and proposed by a licensed

distribution company. Distribution and transmission connection tariffs are both intended

to cover costs incurred when users connect to the grid. Moreover, users of the distribution

system are subject to a standard connection charge (depending on connection capacity and

distance).

3. Transmission tariff: The tariff is drawn up by TEIAS and includes three additional

components. The first is the “use of transmission” price, which covers the investment,

operation and maintenance of the network. It is calculated separately for each region, and

separately for customers and producers. The second is the “transmission system

operation” price, which covers the costs of operating the NLDC and ancillary services

(uniform prices across all regions). The third component is the “market management”

price, which covers and reflects the costs of operating the MFSC. All of the components

are regulated using a revenue cap method.

4. Distribution tariff: The tariff is drawn up by licensed distribution companies and includes

the use of a distribution system price. It is subject to a hybrid revenue and price cap.

5. Retail tariff: The tariff is drawn up by supply license holders for the sale of electricity

and/or capacity to non-eligible customers, and includes retail prices and service prices.

The retail sales price reflects the average cost of energy purchased by retail companies

plus a gross profit margin cap. The retail service price covers the costs associated with the

provision of retail services, and is regulated via a revenue cap. The retail tariff also

includes an average loss and theft price cap. It is quite problematic in terms of the model

due to the different loss ratios between regions.

6. Wholesale tariff of TETAS: This tariff is intended to cover the average cost of wholesale

electricity bought by TETAS and to ensure the financial viability of TETAS.

All of the above listed tariffs must be approved by EMRA. Retail tariffs only apply to non-

eligible customers and to those eligible customers who haven’t chosen their own suppliers yet

via bilateral contracts. All tariffs for bilateral contracts at the retail level are determined freely

(Atiyas et al., 2012, p. 26). This also means that retail prices for eligible customers are

determined freely.

With regard to tariffs drawn up by distribution license holders, the so-called “transitional

price equalization mechanism” is applied in order to protect customers against price

differences that may arise due to cost differences between distribution areas. The transitional

period for the price equalization mechanism has been extended until the end of 2015 (Ergun

Benan & Burcu Tuzcu, 2014).

In addition to the tariffs described above that are determined freely (eligible customers) or

that are regulated (non-eligible customers), the final retail price also includes taxes. Value-

added tax (VAT) accounts for 18% of the consumption bill, and is calculated on the basis of

consumed quantity of electricity. Other taxes specific for the sale and consumption of

electricity include an electricity consumption tax (at rates of 1% and 5%, depending on the

type or purpose of electricity consumption) and the Turkish Radio and Television Corporation

(TRT) tax (tax is calculated on the consumed quantity of electricity at a rate of 2%)

(Eurelectric, 2012, p. 69).

56

In 2014, the European Commission published its “Energy prices and costs in Europe” report,

in which primarily data for 2012 are analysed. The report covers EU Member States, Turkey

and other selected countries. The report shows that the final price paid by electricity

customers in Turkey was €0.147/kWh. The price includes the cost of energy, network costs

and taxes. Energy represents 56% of the final price or €0.083/kWh. This part of the price is

negotiated freely for eligible customers, while this tariff is approved by EMRA for non-

eligible customers. The total amount of network-related costs was €0.034/kWh or 23% of the

total retail price. The remaining 20%, or €0.03/kWh, is accounted for by taxes (European

Commission, 2014a, p. 183).

The data for 2013 show that the average retail price (excluding taxes) for household

customers in Turkey was €0.1186/kWh, which is slightly above the EU 28 average. The price

falls in the range of prices of Portugal, Greece, Poland and the Czech Republic (Figure 23). In

addition, the average retail price (excluding taxes) for industrial customers was €0.0891/kWh

in the same year. Turkey is below the EU 28 average, and falls in the range of the prices of

Poland and Denmark (Figure 24).

Figure 23. Retail prices for household customers in Turkey and EU countries (2013)

Note: Average national price in €/KWh, excluding taxes, applicable for the first semester of the year for

medium-sized household customers.

Source: Eurostat – Energy price statistics, 2014.

Figure 24. Retail prices for industrial customers in Turkey and EU countries (2013)

0

0,05

0,1

0,15

0,2

0,25

Irel

and

Sp

ain

Un

ited

Kin

gd

om

Bel

giu

m

Ital

y

Ger

man

y

Lu

xem

bou

rg

Au

stri

a

Slo

vak

ia

No

rway

EU

(28

co

un

trie

s)

Sw

eden

Net

her

lan

ds

Den

mar

k

Cze

ch R

epu

bli

c

Po

rtu

gal

Tu

rkey

Slo

ven

ia

Gre

ece

Po

lan

d

Lit

hu

ania

Fin

lan

d

Cro

atia

Hu

ngar

y

Fra

nce

Est

on

ia

Lat

via

Rom

ania

Mo

nte

neg

ro

Icel

and

Bulg

aria

€/k

Wh

Turkey: €0.1186/kWh

EU 28: €0.137/kWh

57

Note: Average national price in €/kWh, excluding taxes, applicable for the first semester of the year for medium-

size industrial customers.

Source: Eurostat – Energy price statistics, 2014.

Figure 25 illustrates prices for industrial and household customers between 2010 and 2014.

Figure 25. Retail prices for industrial and household customers in Turkey (2010–2014)

Note: Average national price in €/kWh, excluding taxes and levies, for medium-sized industrial and household

customers. The average price of two published Eurostat estimates is calculated for a selected year.

Source: Eurostat – Energy price statistics, 2014.

0,0874

0,0745

0,0876 0,084

0,07495

0,10795

0,09485

0,11065 0,11195

0,09975

0

0,02

0,04

0,06

0,08

0,1

0,12

2010 2011 2012 2013 2014

€/K

WH

Industrial consumers Household consumers

0

0,02

0,04

0,06

0,08

0,1

0,12

0,14

Irel

and

Slo

vak

ia

Lit

hu

ania

Sp

ain

Un

ited

Kin

gd

om

Ital

y

Gre

ece

Po

rtu

gal

Cze

ch R

epu

bli

c

Lat

via

Cro

atia

EU

(28

co

un

trie

s)

Lu

xem

bou

rg

Bel

giu

m

Hu

ngar

y

Rom

ania

Den

mar

k

Tu

rkey

Po

lan

d

Au

stri

a

Ger

man

y

Est

on

ia

Slo

ven

ia

No

rway

Bulg

aria

Sw

eden

Net

her

lan

ds

Fra

nce

Fin

lan

d

€/k

Wh

Turkey: €0.0891/kWh

EU 28: €0.094/kWh

58

4 ASSESSMENT OF ELECTRICITY MARKET DEVELOPMENTS IN

TURKEY

4.1 Level of harmonization of Turkey’s electricity market with EU

legislation and practices

Turkey’s first alignment with the EU acquis on electricity market liberalization came with the

enactment of the 2001 EML (No. 4628). In terms of vertical unbundling, TEAS was divided

into TEIAS, TETAS and EUAS. Each of the new entities was organized as a separate legal

entity. The elements of unbundling required under the First Electricity Directive were the

separation of management and the unbundling of accounts. Hence, the EML exceeded this

requirement through legal unbundling. In addition, the TSO requirement was also met, since

TEIAS was responsible for transmission facilities, investments in the transmission

infrastructure, and balancing and settlement procedures. TEDAS was responsible for the

distribution of electricity, but it also covered some retail trading activities (which were later

transferred to TETAS) (Atiyas & Dutz, 2004, p. 11).

The EML also met the target regarding market opening. All customers who consumed more

that 9GWh a year were designated as eligible customers. Moreover, the newly established

authorization procedure provided entry opportunities in the areas of generation, wholesale,

distribution, retail, import and export. This was also in line with First Electricity Directive

requirements. In addition, the EML required an rTPA regime to access the transmission and

distribution networks. The EML also brought about a new market structure based on bilateral

contracts, but did not envisage a power exchange in the near future (Atiyas & Dutz, 2004, pp.

10-12).

As was the case in EU Member States, many challenges remained to be overcome following

the implementation of the Fist Electricity Directive. Monopolies on the market and a lack of

competition were major problems. According to Atiyas & Dutz (2004, p. 14), the main

challenge in Turkey was to find an exit from the old system. The state was the owner of

generation assets, and was also involved in other parts of the electricity industry, including

trade, transmission and distribution. For this reason, competition was not enabled. In addition,

financial difficulties arose in the distribution segment due to an inefficient tariff system.

Although EU Member States were required to designate an independent regulator under the

Second Electricity Directive, Turkey fulfilled this condition with the 2001 EML through the

establishment of EMRA. Moreover, amendments to the EML adopted in 2008 brought full

compliance with the Second Electricity Directive (EBRD, n.d., p. 165). The exceptions were

cross-border trading and the market opening rate. Nevertheless, Turkey has accelerated the

liberalization process since 2008. The privatization of distribution companies has been

completed. Generation companies are also in the process of privatization, while the market

opening rate reached 85%. The main reasons for the delayed privatization of distribution

assets are the insufficient infrastructure in distribution regions, highly divergent loss and theft

ratios between regions and increasing electricity demand (Cetinkaya, Basaran & Bagdadioglu,

2015b).

59

Cross-border trading has increased as well. Moreover, Turkey’s electricity network has been

fully and permanently integrated with Continental Europe since April 2014. With expected

100% market openness in 2016, Turkey is moving towards integration with the EU and its

practices. In 2013, a new EML was enacted with the primary objective of establishing a

stable, competitive and transparent market. With the implementation of all recent

amendments to the relevant legislation, Turkey is expected to be compliant with the Third

Electricity Directive.

Nevertheless, there is still room for improvement on the market. Each year, the European

Commission prepares a Turkey Progress Report, as a part of its Enlargement Report, in which

it assess the progress made over the last year by candidate countries for EU accession. Such

reports reflect a country’s ability to assume the obligations of membership outlined in the 33

chapters of the acquis, one of them being the Energy Chapter, which has not yet opened due

to a veto by the Republic of Cyprus (Öztürk, 2014). Table 12 summarizes the current status of

Turkey regarding the Energy Chapter, with a focus on electricity.

Table 12. Harmonization with EU legislation and practices

Harmonization with

EU standards

Current status (2014)

Electricity market

prices

Automatic pricing mechanisms that link end-user prices to a cost-based

methodology are envisaged. Nevertheless, the government continues to

set end-user prices (the period was extended until the end of 2015) and

has thus effectively suspended automatic pricing mechanisms.

Privatization Privatization activities were stepped up (total volume of completed

transactions increased from €2.3 billion in 2012 to €9.2 billion in 2013).

The privatization of generation assets has remained limited due to

difficulties experienced by potential investors in securing the necessary

financing.

Security of supply Completion of electricity interconnections with Bulgaria and Georgia.

Turkey contributed to the energy security stress test carried out by the

EC.

Internal energy market Turkey’s legislation is in line with the EU acquis; the majority of

pending implementing regulations were adopted with the new EML.

Customer eligibility Threshold level is 4,500kWh for 2014, which corresponds to a

theoretical market opening rate of 85%. The aim is to reach full market

opening by 2016 to be in line with EU practices.

Energy exchange EPIAS was established (privately and publicly owned).

Renewables – feed-in

tariffs

Prolonged for 10 years, starting in 2016.

Other activities and

instruments related to

renewables

EMRA issued an invitation for pre-licence applications for 3,000 MW of

wind power plants. Evaluation of the pre-license applications for 600

MW continued.

Nuclear energy Turkey and Japan signed an agreement in October 2013 to build the

country’s second nuclear power plant in Sinop (4,500 MW). Turkey and

Japan also signed an agreement to use the nuclear energy for peaceful

purposes.

Source: European Commission, Turkey Progress Report, 2014b, pp. 23-28.

60

Specifically, improvements need to be made in the areas of electricity prices, privatization,

transparency and market openness. Cross-subsidization between customers in the wholesale

and retail electricity markets should be further avoided.

4.2 Future challenges

Although Turkey took concrete steps related to the development of its electricity market,

particularly with the adoption of the new EML, several challenges remain to be overcome in

the future.

At the retail level, there are still some shortcomings that are causing a distortion of

competition. Two major deficiencies are the high level of distribution losses (loss and theft

ratio) and the current tariff regulation. There are major regional differences between the loss

and theft ratios of the 21 distribution regions. For example, regions in Eastern Turkey, such as

Dicle and Vangolu, are the most challenging, since they recorded loss and theft ratios of 75%

and 55% respectively in 2012. Annual electricity consumption was approximately 61 million

MWh in 2012, while overall distribution losses were 25% or 24 million MWh. The highest

losses were between June and August, which are the hottest months of the season (Cetinkaya

et al., 2015b). Figure 26 shows loss and theft ratios for 2013, where again the Dicle and

Vangolu regions recorded extremely high losses. The majority of other regions recorded

losses was below 10 %.

Figure 26. Distribution losses (loss and theft ratios), 2013 in percentages

Source: M. Cetinkaya et al., Barriers to competition in the Turkish electricity market, 2015a, p. 12.

In 2013, Turkey experienced total system losses equal to 16.5% (13.3% in distribution and

2.5% in transmission) of total electricity output (TurkStat, 2014). Those numbers are much

lower in EU Member states. For example, Germany, Italy, Slovenia, Austria, Finland and

61

Greece recorded losses of 4%, 7%, 5%, 6%, 3% and 5% respectively (World Bank data,

2014). On the other hand, all SEE contracting parties are experiencing the same problems as

Turkey in terms of high system losses. As shown in Table 13, all countries have system losses

above 10%, with Albania recording exceptionally high losses of more than 45%.

Table 13. System losses by SEE contracting parties, 2013 in percentages

Source: Energy Community Secretariat, Annual Implementation Report 2013/2014, 2014.

According to the paper of Tasdoven, Fiedler & Garayev (2012, pp. 230-232), grants and

public information could be an effective solution to the illegal use of electricity in Turkey, in

addition to economic regulation and privatization. The paper proposes government-awarded

grants that should be given to private institutions and universities. They would carry out a

three-stage research project. The first stage involves research of the real reasons for

distribution losses. Although there is statistical data available regarding the number of losses

and underlying reasons, the experiences of many developing countries have shown that

government-affiliated agencies may provide biased information if they want to limit public

knowledge of theft. The second stage would involve identifying fraudulent use. The aim of

stage three is to design and conduct surveys in order to determine to what extent citizens are

aware of consumption that is harnessed separately from regulated transmission lines and is

thus considered a crime. All of these data would then be publicly disclosed or delivered to

customers via public campaigns aimed at influencing the behaviour of the target audience.

The most important issue relating to loss and theft ratios is the current tariff structure. Since

an equalization mechanism is applied, prices are the same for all regions. Consequently, the

losses incurred by higher-cost regions are borne in part by the customers of low-cost regions.

The costs of regions with high losses are cross-subsidized by regions with low losses. Such a

policy is not sustainable in the long run, although it is acceptable in the short term for

privatized firms, whose interest it is to recoup the high amount of investments required for the

privatization process. Privatized distribution companies have a regulatory obligation to

achieve target annual loss and theft ratios. However, actual ratios are not in line with the

commitments made by those companies. Current EMRA policy is therefore not appropriate

for overcoming the problem of high distribution losses (Cetinkaya et al., 2015a, p. 12).

In term of electricity generation, the completion of the privatization process for generation

assets and source diversification represent future challenges, as well. The Turkish

Contracting

parties

Ukraine Serbia Montenegro Moldova Macedonia Bosnia and

Herzegovina

Albania

Losses in

transmission

2.42 2.40 4.28 2.90 2.00 1.81 2.3

Losses in

distribution

10.17 14.90 18.96 10.70 16.40 11.55 45.04

Total system

losses

12.59 17.3 23.24 13.6 18.4 13.36 47.34

62

government has tried to attract foreign investors to participate in tenders for generation assets.

Interest, however, was very limited. In the end, mainly domestic construction and energy

companies submitted bids in 2014, with much lower figures than in 2013. This was due to the

depreciation of the Turkish lira vis-à-vis foreign currencies. In terms of financing,

international banks have not been active, while the political elections in 2014 also slowed

several economic activities (Durakoğlu, 2014). The successful completion of the privatization

process can help reduce the government’s influence over the electricity market, resulting in

increased competition (Cetin, 2014, p. 104).

Turkey’s population is forecasted to exceed 83 million in 2020. The country also faces

increasing electricity demand, which will have reached 435 TWh by 2020 (Bilgili, 2009, p.

246). To that end, it is important to ensure a sufficient electricity supply for the future.

Currently, Turkey is highly dependent on imported natural gas (Figure 27). This is a very big

challenge in terms of source diversification and the security of supply. One of the problems of

natural gas dependency is that when natural gas supply becomes limited, the price of

electricity on the spot market is expected to rise due to the associated scarcity, resulting in the

increased use of alternative (and expensive) generation sources (Camdan & Kolmek, 2013, p.

68). In 2012 (13 February), for example, there were heavy winter conditions, resulting in a

significant decrease in the natural gas supply from Azerbaijan and Iran, which was

accompanied by a simultaneous sharp rise in domestic consumption. Thus, gas-fired power

plants faced problems in generation, and the price on the day-ahead market reached 2,000

TL/MWh, which is 10 times higher than the average high level of 200 TL/MWh (Camdan &

Kolmek, 2013, p. 68).

Figure 27. Share of natural gas in electricity generation

Source: TurkStat, 2014.

0,00%

10,00%

20,00%

30,00%

40,00%

50,00%

60,00%

Share of natural gas in electricity

generation

63

It is therefore important for Turkey to strive to reduce its dependence on natural gas imports.

The aim of its national energy strategy is to further increase the use of hydro, wind and solar

energy resources, since its potential for renewable energy resources is substantial. Secondly,

the gradual introduction of nuclear power into the country’s energy mix is also a part of the

strategy (Republic of Turkey – Ministry of Foreign Affairs, 2015). Nevertheless, the

liberalization of the natural gas market also plays an important role, particularly in terms of

reducing the market share of BOTAS and thus enabling competition.

The wholesale market is rapidly transforming into a competitive market, which has resulted in

the identification of manipulation risks. In general, electricity markets can be manipulated for

several reasons, including: (i) a lack of elasticity on the electricity markets, which results in

unexpected price volatility when a small decrease in distribution occurs; (ii) storage

difficulties, which lead to an obligatory well-balanced electricity market; (iii) generation

companies may gain market power as price determinants when transmission issues arise; (iv)

producers usually operate at maximum capacity with regard to their marginal cost, and are

thus unable to adapt to price increases (Herdem, 2014).

Due to the potential manipulation risks stated above, it is necessary to have an authorized

body that deals with such potential manipulation. The EU has enacted the Regulation on

Energy Market Integrity (REMIT), while ACER is authorized to collect data and observe

markets. In Turkey, there is a lack of REMIT-type rules that require market participants to

regularly report their wholesale market contracts. Thus, new secondary legislation is urgently

needed in the future to stimulate market confidence (Herdem, 2014; Santos, 2015).

CONCLUSION

This master’s thesis offers an analysis of the Turkish electricity market following the major

reform thereof. Turkey’s harmonization with EU legislation and practices is also reviewed.

The EU restructured its energy markets via three energy packages adopted in 1996, 2003 and

2009. The three electricity directives were the main instruments in the process of introducing

competition to national markets. The main objective of the electricity directives was to

introduce competition to the market, and to ensure the transparency and financial stability of

the markets and the security of supply. Regional markets represented the next step towards

creating an internal electricity market. EU Member States formed seven electricity regions

that share a similar economic and political environment.

In addition to the seven electricity regions, which cover the electricity markets of EU Member

States, an eighth region was also established. It is also referred to as the SEE region and

covers the Energy Community contracting parties, as well as neighbouring EU countries.

Turkey has the status of Energy Community observer, with the goal of becoming an EU

Member State, as well as Energy Community contracting party. Turkey is thus following EU

practices in order to ensure competition on the market.

64

The first major change on the Turkish electricity market occurred with the enactment of the

EML in 2001. The EML vertically unbundled TEAS into the following new publicly owned

entities: TEIAS (transmission), TETAS (trading) and EUAS (generation). In addition, the

regulator EMRA was established and the concept of eligible customer defined. A new market

structure was also introduced, comprising bilateral contracts and a balancing mechanism. The

EML was subsequently amended in 2008, while a new EML entered into force in 2013. Both

were aimed at accelerating the liberalization process and achieving compliance with EU

legislation and practices.

The role of the publicly owned EUAS is decreasing in the generation segment, where a higher

private-sector presence is expected in the future, since new plants are being built by the

private sector. In addition, several EUAS power plants are currently included in the

privatization process. Electricity is mainly generated from natural gas, coal and hydro

sources. Although the country is historically dependent on imported natural gas, renewables

are gradually achieving a higher market share and enabling Turkey to diversify its resources

for electricity generation. In addition, two nuclear power plants are expected to be built and

operational in the future.

Transmission lines are operated by the publicly owned TEIAS, Turkey’s TSO. It maintains

the transmission network and it conducts auctions for transmission capacities.

Major changes have occurred recently on the wholesale market. The market is currently being

transformed into a competitive, financially stable and transparent wholesale market. The

current hybrid model, which comprises bilateral contracts and a balancing mechanism, will be

replaced by the EPIAS power exchange, which will cover the spot market on a day-ahead and

intraday basis. Derivatives will continue to be traded on the Borsa Istanbul, while TEIAS will

be responsible for the balancing market. With more available capacities expected on the

Bulgarian and Greek borders (ENTSO-E connections), through improved transparency and

with its own power exchange, the Turkish power market is likely to become a leader in the

region.

The retail and distribution markets were recently unbundled. There are now 21 privatized

distribution companies, each acting as a DSO for its own region. The retail market has been

separated, and enables private companies to enter the market and sell electricity to eligible

customers. The current rate of market opening is 85%, with the market expected to be fully

open in 2016.

As can be noted, Turkey has put major efforts into the process of transforming its former

vertically integrated electricity market into a fully competitive and transparent electricity

market. It is following the example of EU Member States, and is trying to offer market

players a competitive market place. Nevertheless, this is a complex process and Turkey still

has many challenges to overcome.

The most concerning are the level of distribution losses, which are extremely high in some

regions (up to 75%). Related to those losses are inappropriate regulated tariffs that are equal

for all the regions. This is not efficient over the long run, since the losses of higher-cost

regions are borne by the customers of the low-cost regions.

65

Moreover, dependence on imported natural gas should be reduced, since electricity prices are

affected by potential changes on the gas market. Accordingly, the natural gas market in

Turkey should be liberalized and made more competitive with the aim of achieving more

competitive prices. Wholesale electricity markets are also exposed to manipulation risks, and

should implement REMIT-type rules in order to stimulate market confidence.

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0

APPENDIXES

0

LIST OF APPENDIXES

Appendix A: Summary – Povzetek v slovenskem jeziku (na osnovi magistrskega dela)

……..……………………………………………………..…………………………………….1

Appendix B: List of abbreviations …………….…………………………………….……….10

Appendix C: Table illustrating the Turkish electricity market and selected SEE electricity

markets ………………………………………………..……………………………………...11

Appendix D: Table of feed in tariffs (for selected countries)

………………………………………………………………………………………...…...…13

Appendix E: Transmission lines in Turkey ………………………………………………….16

1

APPENDIX A: Summary – Povzetek v slovenskem jeziku (na osnovi magistrskega dela)

Glavni lastnosti trgov z električno energijo sta bili ekonomija obsega v proizvodnji električne

energije in dejstvo, da mora slednja preko obsežnega prenosnega in distribucijskega sistema,

preden je dobavljena končnim odjemalcem. Zaradi teh karakteristik so v dvajsetem stoletju

trge električne energije obvladovala podjetja, ki so bila v državni lasti. Obenem so bila ta

podjetja vertikalno integrirana v vse dejavnosti elektrogospodarstva in imela monopol na trgu

(Kopsakangas – Savolainen in Svento, 2012, p. 5).

Zaradi velikega nezadovoljstva, povezanega s takšno organiziranostjo trga, je veliko držav

začelo z reorganizacijo delovanja trgov električne energije. Obstajalo je veliko empiričnih in

teoretičnih dokazov, predvsem o prednostih konkurence in o nevmešavanju države v

delovanje trga. Dejavniki, ki so omogočili reforme v elektrogospodarstvu, pa so bili: nove

proizvodne tehnologije (te so zmanjšale optimalno velikost elektrarn), zahteve po povečanju

stroškovne učinkovitosti monopolnih podjetij in splošno prepričanje, da država ni ustrezen

lastnik (predvsem zaradi prepočasnega odzivanja na ekonomske in tehnološke spremembe)

(Hrovatin in Zorić, 2011).

Skupaj z globalnim trendom je tudi Evropska unija (EU) začela s prestrukturiranjem trgov

električne energije v državah članicah. Glavni cilj EU je ustvariti notranji trg z učinkovito

konkurenco, ki prinaša dobrobit potrošnikom (zaradi konkurence se cene električne energije

nižajo) in udeležencem na trgu (zaradi preprečevanja monopolistične situacije na trgu)

(Bockers et al., 2013, str. 7). Splošno gledano se v procesu liberalizacije trgov z električno

energijo odvijejo štirje glavni koraki, ki vodijo k bistvenih spremembam na trgu (Jamasb in

Pollit, 2005, str. 13):

- Prestrukturiranje: vertikalna ločitev proizvodnje, prenosa, distribucije in dobave električne

energije končnim kupcem.

- Konkurenca in trgi: oblikovanje trga na debelo in trga na drobno, uvedba konkurence.

- Regulacija: ustanovitev neodvisnega regulatorja trga, dostop do omrežja, regulacija za

distribucijsko in prenosno omrežje.

- Lastnina: privatizacija državnih podjetij in omogočanje vstop novim, zasebnim podjetjem

na trgu.

Vsi zgoraj navedeni koraki so bili v državah članicah EU sproženi z reformo, ki je bila

izvedena z dvema vzporednima procesoma. Prvi je bil uvedba smernic za vzpostavitev

notranjega trga električne energije v EU (Direktiva 96/92/EC, Direktiva 2003/54/EC in

Direktiva 2009/72/ES). Drugi proces pa je bil vzpodbujanje razširitve čezmejnih prenosnih

povezav skupaj z izboljšavo pravil za čezmejno trgovanje (Karan in Kazdagli, 2011, str. 13;

Jamasb in Pollitt, 2005, str. 17).

Zahteve Direktiv EU o oblikovanju notranjega trga z električno energijo so predstavljene v

tabeli 1.

2

Tabela 1. Direktive EU o oblikovanju notranjega trga z električno energijo

Določbe Prva direktiva

(1996) Druga direktiva

(2003)

Tretja direktiva

(2009)

Proizvodnja (gradnja

novih proizvodnih

zmogljivosti)

Omogoča novim

igralcem na trgu

izgradnjo na podlagi

dovoljenja ali razpisa

Dovoljenje Dovoljenje

Razpis (energetska

učinkovitost,

menedžment

povpraševanja)

Prenos (T) ,

distribucija (D)

(dostop do omrežja)

Regulirani TPA,

izpogajani TPA, edini

kupec

Regulirani TPA Regulirani TPA

Dobava (vertikalna

ločitev)

Ločitev računovodskih

izkazov

Funkcionalna ločitev

od prenosa in

distribucije

Funkcionalna ločitev

od prenosa in

distribucije

Uporabniki

(odpiranje trga)

Izbira za upravičene

odjemalce (do 1/3

končne porabe)

Vsi negospodinjski

odjemalci od leta

2004, vsi odjemalci od

leta 2007

Vsi

Ločitev T

Ločitev D

Računovodski izkazi Pravna ločitev Lastniška (T)

Pravna (vertikalno

integrirana podjetja

(T) in upravljavska,

neodvisna SOPO (T)

Pravna (D)

Čezmejna trgovina Pogajanja Regulirana Regulirana, ENTSO

Regulacija Ni določena Regulatorni organ

(NRA)

European Regulators'

Group for Electricity

and Gas (ERGEG)

Močno povečana

neodvisnost in

pristojnosti NRA

Ustanovljena ACER

Vir: N. Hrovatin in J. Zorič, 2011, Reforme elektrogospodarstva v EU in Sloveniji, str. 7.

Kot je prikazano v tabeli 1, so se spremembe v EU uvajale postopoma. Po uvedbi prve

direktive (1996) je bilo na trgu namreč še veliko pomanjkljivosti, predvsem gre omeniti

pomanjkanje transparentnosti in tehnične težave, ki so onemogočale dostop do omrežja.

Polega tega pa so bili monopoli še vedno prisotni na trgu (Kovacs, 2011). Z uvedbo druge

direktive sta bila omogočena konkurenca na trgu proizvodnje električne energije in dostop do

omrežja, vendar je bilo prisotno veliko pomanjkanje konkurenčnih in likvidnih trgov prodaje

električne energije na debelo. Sistemski operaterji prenosnega omrežja (SOPO) in sistemski

operaterji distribucijskega omrežja (SODO) v praksi še vedno niso bili vertikalno ločeni,

monopolistične situacije pa so še vedno predstavljale težave za nemoteno delovanje trga, saj

so onemogočale konkurenco (Thomas, 2006; Jakovac, 2012, str. 321). Z uvedbo tretje

direktive so se razmere na trgih električne energije v EU občutno izboljšale, saj so danes vsi

trgi liberalizirani, prisotna je večja transparentnost in zanesljivost. Stopnja konkurence je

občutno višja, prav tako pa so trgi bolj likvidni.

3

Ne glede na dosežke prestrukturiranja trgov električne energije v EU so prihodnji izzivi za

trge prodaje električne energije na drobno predvsem: heterogenost nacionalnih energetskih

politik, ki se odraža v raznolikosti cen električne energije znotraj EU (katerih sestavni del so

davki in dajatve za omrežje), nesodelovanje potrošnikov pri menjavi dobavitelja električne

energije in potreba po platformi, ki bi omogočala primerjavo cen v EU. Poudariti pa je

potrebno tudi pomembnost transparentnih računov, ki jih potrošniki prejmejo na dom (ACER,

2014).

Nekaj priložnosti za izboljšavo delovanja trga je tudi na trgih prodaje električne energije na

debelo. Za namen integracije nacionalnih trgov, na poti do notranjega trga električne energije

EU, so se izoblikovali regionalni trgi. Ti so sestavljeni iz držav, ki jih druži predvsem

podobno ekonomsko in politično okolje. Oblikovanih je sedem regionalnih trgov, ki

združujejo delovanje NRA, komisije in SOPO-ov. Tako imenovane Regionalne iniciative (RI)

prinašajo izmenjavo informacij in dobrih praks kot tudi implementacijo Kodeksov omrežja

(ACER, 2013, str. 16). ACER želi na regionalnih trgih doseči implementacijo štirih ciljnih

modelov, ki bi izboljšali čezmejno sodelovanje in integracijo trgov. Ti modeli se navezujejo

na spajanje trgov, trgovanje znotraj dneva, dolgoročne čezmejne prenosne zmogljivosti (ČPZ)

in metode za izračun kapacitet. Pozitivni učinki uvedbe teh modelov so predvsem učinkovita

uporaba ČPZ in zvišanje konvergence cen električne energije na debelo (ACER/CEER, 2014,

str. 16). V prihodnje se torej pričakuje implementacija ciljnih modelov na vseh regionalnih

trgih na debelo.

Poleg sedmih regionalnih trgov pa je nastala tudi tako imenovana osma regija ali regija

Jugovzhodne Evrope (regija SEE). Države SEE združujejo podobni energetski problemi, kot

so: majhni energetski trgi, energetsko intenzivna gospodarstva, slaba infrastruktura in

razlikovanje nacionalnih energetskih politik od politik EU (Karova, 2011, str. 81). Države

SEE so vse podpisnice Energetske skupnosti (ang. Energy Community) (Albanija, Bosna in

Hercegovina, Makedonija, Kosovo, Moldavija, Črna gora, Srbija in Ukrajina), poleg pa so še

sosednje države članice EU (Bolgarija, Hrvaška, Grčija, Italija, Madžarska, Romunija in

Slovenija). Gruzija ima status kandidatke, medtem ko imajo Turčija, Armenija in Norveška

status opazovalke (Energy Community, 2014).

Turčija je šestnajsto največje gospodarstvo na svetu in šesto največje gospodarstvo v

primerjavi z EU v 2013. V letu 2013 je bil njen BDP 820 milijarde USD, populacija pa 76,7

milijonov ljudi z 1,12-odstotno stopnjo rasti (Invest in Turkey, 2014; TurkStat, 2014). Glavna

razloga za visoko povpraševanje po energiji v Turčiji sta torej naraščajoč BDP in naraščajoča

populacija. Slednja naj bi po ocenah dosegla 84 milijonov do leta 2023. Zaradi naraščajočega

povpraševanja po električni energiji, ki temelji na industrializaciji in urbanizaciji, ima Turčija

enega od najhitreje rastočih trgov električne energije na svetu. Povpraševanje po električni

energiji se je v zadnjih desetih letih podvojilo. Leta 2000 je bilo povpraševanje 128 TWh, v

letu 2013 pa 246 TWh (Deloitte, 2014, str. 5; Statistical data, 2013).

V primerjavi z ostalimi državami regije SEE ima Turčija največjo proizvodnjo električne

energije, saj je v letu 2013 proizvedla približno 240 TWh (240.154 GWh), medtem ko je bila

proizvodnja v regiji SEE sledeča: Albanija (5.956 GWh), Bosna in Hercegovina (16.303

GWh), Makedonija (5.676 GWh), Moldavija (748 GWh), Črna gora (389 GWh) in Srbija

4

(27.537 GWh) (priloga C). Glede na to, da je likvidnost ena bistvenih komponent trgov za

trgovanje z električno energijo na debelo, Turčija pozitivno vpliva na regijo SEE, saj ji

povečuje likvidnost.

V preteklosti je na turškem trgu električne energije (kot tudi drugod po svetu) delovalo

vertikalno integrirano podjetje, monopolist na trgu z imenom Turkiye Elektrik Kurumu

(TEK). Ta je bil ustanovljen leta 1970 z namenom združitve proizvodnje, prenosa, distribucije

in dobave električne energije pod en integriran sistem. Kasneje je bil TEK ločen na dve

podjetji, TEAS (podjetje za proizvodnjo električne energije) in TEDAS (podjetje za

distribucijo, prenos in dobavo električne energije) (TEIAS, 2014).

Izvedenih je bilo veliko poskusov, ki bi lahko pritegnili zasebni kapital na trg, a v večini

primerov je bila privatizacija blokirana, ker država ni želela tujih investitorjev v tako strateški

industriji. Prisotnost zasebnega sektorja na trgu električne energije je bila omogočena šele v

letu 1984 z zakonom št. 3096, ki je vpeljal dva nova tipa pogodb na trg (Cetin in Oguz, 2007,

str. 1763):

- BOT (ang. Build-Operate-Transfer): S to pogodbo je zasebnemu podjetju podeljena

koncesija za izgradnjo in upravljanje elektrarne za obdobje do 99 let (kasneje skrajšano na

49 let). Po izteku tega obdobja se sredstva predajo državi, in sicer brez stroškov.

- TOR (ang. Transfer of operating rights): Ta pogodba omogoča zasebnemu podjetju, da

upravlja z že obstoječo elektrarno ali distribucijskim omrežjem, ki je v lasti države.

Z zakonom št. 4283 je bil vpeljan še en tip pogodbe, in sicer BOO (ang. Built-Operate-Own).

Ta pogodba se nanaša na termoelektrarne, in sicer je zasebnemu podjetju dodeljena licenca, s

katero lahko izgradi, upravlja in si na koncu tudi lasti elektrarno.

Zgoraj opisane pogodbe so imele veliko pomanjkljivosti, predvsem pa niso prispevale k

oblikovanju konkurence na trgu. Poleg tega je bil tu prisoten še vpliv iz tujine, predvsem s

strani mednarodnih institucij, kot so IMF, OECD in Svetovne banke. Le-te so poudarjale

potrebo po reformah na trgu električne energije v Turčiji. Ravno tako pa je reforma trga

električne energije eden od predpogojev za izpolnitev dolgoročnega cilja, in sicer članstva v

EU (Erdogdu, 2006, str. 986). Vsi ti sprožilci so pripeljali do prvih resnejših ukrepov, ki so

omogočali konkurenco na trgu.

Leta 2001 je bil sprejet zakon št. 4628, EML (ang. Electricity Market Law). Ta je prvi

pripeljal konkretne reforme na turški trg električne energije. Tako kot v drugih državah je

imela tudi Turčija kar nekaj težav z izhodom iz starega sistema delovanja. Sledil je

posodobljen zakon v letu 2008. Tudi za tem je ostalo kar nekaj pomanjkljivosti na trgu, zato

je bil leta 2013 sprejet zakon št. 6446, novi EML. Določbe zakonov so predstavljene v tabeli

2.

Kot je predstavljeno v tabeli 2, je turška zakonodaja sledila zgledu EU in skušala biti

usklajena s prakso EU. Proces prestrukturiranja trga z električno energijo je kompleksen in

dolgotrajen, zato so se spremembe na trg uvajale postopoma. Turčija je vzporedno z

določbami EML izvajala tudi privatizacijo državnih podjetij, zato je v letu 2008 začela s

privatizacijo proizvodnih enot (EUAS) in distribucijskih podjetij (TEDAS).

5

Tabela 2. EML 2001, 2008 in 2013

Določbe EML 2001

(in posodobitev v letu 2008) EML 2013

Vertikalna ločitev

državnih podjetij

TEAS je bil pravno ločen na TEIAS

(prenos), TETAS (trgovanje) in EUAS

(proizvodnja).

TEDAS je določen za distribucijo.

Sredstva TEDAS so privatizirana,

elektrarne EUAS pa so v procesu

privatizacije. Vsa podjetja, ki

imajo več kot eno licenco, morajo

imeti ločene računovodske

izkaze, distribucija in dobava pa

morata biti z 2016 popolnoma

ločeni (lastniško, upravljavsko).

Regulacija Ustanovljena EMRA (neodvisni

regulator).

EMRA

Trg električne

energije na debelo

Nov model delovanja: bilateralne

pogodbe in izravnalni trg z električno

energijo.

Nov model delovanja:

Ustanovitev EPIAS (borza za

trgovanje z električno energijo,

fizično), finančno trgovanje na

Borsa Istanbul, izravnalni trg pa

ima TEIAS.

Licence Nove licence: proizvodnja, prenos,

distribucija, dobava končnim kupcem,

proizvajalci, ki proizvajajo za lastno

rabo.

Nove licence: predhodna licenca

za proizvodnjo, licenca za oskrbo,

licenca za upravljanje trga. Poleg

navedenih so ostale še: licenca za

proizvodnjo, prenos, distribucijo.

Uporabniki Opredeljen je upravičen odjemalec. Vsi

ki porabijo več kot 9 GWh na letni

ravni.

Meja za upravičene odjemalce se

je znižala na 4500 kWh porabe na

leto, trenutno je trg odprt 85-

odstotno. V 2016 se pričakuje

100-odstotno odprtost.

Dostop do omrežja Regulirani TPA Regulirani TPA

Čezmejna trgovina Monopol državnih podjetij (TETAS,

TEIAS)

Sinhronizirana povezava z

omrežjem ENTSO-E (Bolgarija,

Grčija), omogočeno komercialno

čezmejno trgovanje, vsem

akterjem na trgu

Proizvodnja

(gradnja novih

proizvodnih

zmogljivosti)

Dovoljenje Dovoljenje

Vir: EMRA, Electricity Market Report 2010, n.d., str. 3; Atiyas et al., Competition and Regulatory Reform in the

Turkish Electricity Industry, 2012, str. 23; Electricity market law No.4628, Official Gazette No. 24335.

Najprej se je, v letu 2008, začela izvedba privatizacije distribucijskih podjetij. Turško

distribucijsko omrežje se je razdelilo na 21 regij. TEDAS je nato ustanovil 20 novih podjetij,

saj je bilo eno podjetje oziroma regija že predhodno v privatni lasti – Kayseri. Vsako podjetje

se je takrat obnašalo kot regionalni monopolist na svojem območju in je izvajalo tako

6

distribucijske aktivnosti kot samo dobavo električne energije. 18 podjetij je bilo privatiziranih

preko javni pisnih ponudb za nakup, ostali dve pa sta bili privatizirani v sklopu drugih

postopkov (Celen, 2013, str. 675 – 676). Privatizacija je bila izvedena z modelom TOR, torej

je TEDAS ostal lastnik distribucijskega omrežja, zasebno podjetje pa upravljalec omrežja.

Privatizirana podjetja so morala ustanoviti ločeno podjetje za izvajanje dobave električne

energije končnim potrošnikom, to dejavnost opravljajo z licenco za oskrbo. Za distribucijske

aktivnosti jim je bila dodeljena distribucijska licenca. Z letom 2016 pa se zahteva tudi fizična

ločitev delovanja, torej uporaba ločenih prostorov ter ločenih računovodskih in pravnih služb.

Uspešni privatizaciji distribucijskih podjetij je sledila privatizacija proizvodnih enot EUAS-a,

vendar je tu prišlo do zamud, zato je še danes veliko postopkov v teku. Kljub temu so bile

večje elektrarne privatizirane, in sicer: Kangal (457 MW), Kemerkoy (630 MW), Yenikoy

(420 MW), Catalgzi (300 MW), Hamitabat (1156 MW), Seyitomer (600 MW), Soma (990

MW), Orhaneli (210 MW), Tuncbilek (365 MW).

V nadaljevanju sledi pregled trenutnega delovanja trga v obdobju po reformah in privatizaciji.

Proizvodnja električne energije

Z vidika lastništva je na trgu proizvodnje pet vrst akterjev, in sicer: državno podjetje EUAS,

podjetja ki delujejo s pogodbami BOO in BOT, podjetja, ki delujejo s pogodbami TOR,

neodvisni proizvajalci in proizvajalci, ki proizvajajo za lastno rabo. Velik igralec na trgu je še

vedno EUAS, čeprav se situacija spreminja. Od privatizacijskih postopkov, ki so še v teku, pa

pričakujejo večjo prisotnost zasebnih podjetij na trgu. Poleg tega pa so vse novo izgrajene

elektrarne v letu 2013 v lasti zasebnikov, in sicer gre za približno 7000 MW nameščenih

zmogljivosti (MENR, 2014).

V letu 2013 je skupna proizvodnja električne energije v Turčiji znašala 240 TWh. Večina

električne energije je bila proizvedena iz zemeljskega plina (105 TWh), sledita premog (64

TWh) in voda (59 TWh). Manjši delež v proizvodnji predstavljata veter (8 TWh) in

geotermalna energija (1 TWh) (Electricity generation & transmission statistics of Turkey for

year 2013, 2014).

44 % električne energije v Turčiji je proizvedene iz zemeljskega plina. Ta je večinoma uvožen

iz Alžirije, Nigerije, Irana, Azerbajdžana in Rusije. Največji pogodbeni partner je ravno

Rusija, s katero je podpisana dobava skupno 30 bcm na leto, in sicer do leta 2025. Odvisnost

od uvoza zemeljskega plina je zaskrbljujoča, saj povezanost med trgoma vpliva na cene

električne energije (Botas, 2014). Na primer: ko postane dobava zemeljskega plina omejena,

je pričakovan dvig cene na trgih električne energije. Takšen primer se je zgodil 13. 2. 2012,

ko se je zaradi težkih vremenskih pogojev znižala dobava plina iz Azerbajdžana in Irana, na

drugi strani pa se je močno dvignila domača potrošnja. Posledično so imele termoelektrarne

težave pri proizvodnji, cena na trgih z električno energijo pa je dosegla 2000 TL/MWh, kar je

desetkrat višje od povprečnih cen (Camdan in Kolmek, 2013, str. 68). Zaradi opisanega je

dolgoročni cilj Turčije zmanjšati odvisnost od uvoza in doseči večjo konkurenco na trgu

plina.

7

Drugi največji vir proizvodnje je premog (26 % v letu 2013). Turčija ima bogate vire lignita,

ki prispevajo 75 % k celotni oskrbi z premogom. Črni premog pa se nahaja samo v regiji

Zonguldak, kjer je državno podjetje TTK monopolist pri pridobivanju in distribuciji le-tega

(EUROCOAL, 2015).

Eden izmed zelo pomembnih virov za proizvodnjo električne energije pa je tudi voda. Turčija

ima bogate vodne vire, njen potencial vodne energije naj bi bil 140 milijarde kWh na leto, le

35 % tega potenciala pa je dejansko izkoriščenega. V letu 2013 je bila skupna nameščena

zmogljivost 467 hidroelektrarn, to je 22.289 MW. Leta 2006 je bilo v Turčiji nameščenih le

13,1 GW zmogljivosti, medtem ko se je v letu 2013 številka dvignila na 22,3 GW.

Dolgoročno ima Turčija namen namestiti 180 GW skupnih zmogljivosti hidroelektrarn (do

leta 2030).

Za zagotovitev diverzifikacije svojih virov proizvodnje pa se Turčija zanaša tudi na ostale

obnovljive vire energije, predvsem na veter, sonce, geotermalno energijo in biomaso. Cilji za

leto 2030 so, da bi imeli nameščenih 40 GW vetrnih, 4,2 GW geotermalnih in 10 GW sončnih

zmogljivosti ter 2,2 GW biomase (Yuksel, 2013, str. 1040). Da bi se zmanjšala odvisnost od

uvoženega zemeljskega plina, načrtuje Turčija tudi izgradnjo dveh nuklearnih elektrarn s

skupno zmogljivostjo 9280 MW, do leta 2020 pa naj bi se 5 % električne energije proizvedlo

z nuklearno energijo (MENR, 2014).

Prenos električne energije

Oskrba prenosnega omrežja in ostale aktivnosti, povezane z omrežjem, so odgovornost

državnega podjetja TEIAS (TEIAS, 2014). Turčija ima 51.344 km daljnovodov, povezana je z

Grčijo, Bolgarijo, Gruzijo, Iranom, Irakom in s Sirijo. Najpomembnejši povezavi sta Grčija in

Bolgarija, saj je preko njiju Turčija povezana z omrežjem ENTSO-E, kar ji omogoča

trgovanje z državami regije SEE.

Turčija je neto uvoznik električne energije. V letu 2013 je namreč uvozila preko 14.000 GWh

električne energije, izvozila pa le nekaj več kot 2.000 GWh. V preteklosti, pred povezavo z

ENTSO-E, je bila neto izvoznik (do leta 2011). Ena izmed zanimivih povezav za Turčijo je

tudi Gruzija, predvsem zaradi bogatih obnovljivih virov, ki se nahajajo v tej državi, in pa

zaradi visokega povpraševanja po električni energiji v Turčiji (Deloitte Consulting, 2014, str.

2).

Veleprodajni trg električne energije

Trg električne energije na debelo je v fazi razvoja, pričakovati je namreč spremembe,

predvsem z začetkom delovanja EPIAS-a. Trenutno trg deluje na dveh ravneh, ena je trg za

bilateralne pogodbe, druga je izravnalni trg. Pomemben akter na trgu je državni TETAS, ki s

starimi pogodbami z EUAS-om in s podjetji, ki delujejo s pogodbami BOO, zavzema velik

tržni delež. V letu 2013 je imel preko 50 % celotnega nakupa in prodaje na trgu, medtem ko

so se čezmejne aktivnosti TETAS-a zmanjšale zaradi komercialnih avkcij ČPZ.

Poleg fizičnega trgovanja z električno energijo, ki vključuje fizično dobavo električne

energije, pa obstajajo tudi finančni trgi, ki služijo za zavarovanje, predvsem pred cenovnimi

8

tveganji na trgu. Finančno trgovanje z električno energijo se je v Turčiji začelo šele v letu

2011 na TurkDex (ang. Turkish Derivatives Exchange), kasneje pa se je trgovanje prestavilo

na Istanbulsko borzo (Borsa Istanbul).

V letu 2012 je bil celoten volumen trgovanja na Istanbulski borzi 62 milijonov pogodb, s

skupno vrednostjo 200 milijard USD. V istem letu je bil volumen trgovanja s terminskimi

pogodbami za električno energijo le 928 pogodb z vrednostjo 9,5 milijonov USD (Borsa

Istanbul, 2013). Te vrste pogodb ne pritegnejo dovolj interesa, predvsem zato, ker investitorji

menijo, da cene na trgu ne odražajo realnega ravnovesja ponudbe in povpraševanja (Bademli,

2013).

Kar se tiče veleprodajnih cen na turškem trgu električne energije, so v povprečju višje kot

tiste v regijah SEE in CEE (DG Energy – Market Observatory for energy, 2014, str. 10). V

Turčiji je kar nekaj dejavnikov, ki vplivajo na veleprodajne cene. Vreme vpliva tako na

ponudbo kot tudi na povpraševanje po električni energiji. Ko so poletja vroča, se zaradi večje

uporabe klimatskih naprav poveča povpraševanje po električni energiji. Enak učinek imajo

tudi hladne zime, ki povzročijo večjo uporabo naprav za ogrevanje. Vreme sicer vpliva tudi

na nivo ponudbe, predvsem na trgih, kjer je velik delež obnovljivih virov energije. V Turčiji

tako lahko vpliva na proizvodnjo v hidroelektrarnah in na vetrno proizvodnjo. Velik vpliv

predstavljata tudi odvisnost od uvoženega zemeljskega plina in slabo razvita konkurenca na

trgu plina. Uvozne pogodbe so drage, cene na trgu plina pa zaradi slabe razvitosti trga

nekonkurenčne. Poleg navedenega se v času verskih praznikov, kot je na primer bajram,

povpraševanje zelo zmanjša, kar lahko pripelje tudi do cene 0 TL/MWh v določenih urah

dneva. Za Turčijo so značilne tudi visoke izgube v omrežjih, ki posredno vplivajo na

veleprodajne in maloprodajne cene električne energije.

Distribucija in dobava električne energije končnim potrošnikom

Distribucijska dejavnost je ločena od dejavnosti dobave električne energije šele od leta 2013.

V državi je 21 distribucijskih regij, v vsaki je eno podjetje z distribucijsko licenco, ki upravlja

omrežje. Ne glede na to pa je država (TEDAS) še vedno lastnik omrežja.

Največja težava, s katero se spoprijemajo podjetja za distribucijo in posledično tudi podjetja

za dobavo, so visoke izgube električne energije v distribucijskem omrežju. Med regijami so

velike razlike v izgubah, najbolj težavni pa sta Dicle s 75-odstotnimi in Vangolu s 55-

odstotnimi izgubami v letu 2012. Izgube v ostalih regijah znašajo v povprečju okrog 10 % ali

manj. Gre predvsem za tehnične izgube in krajo električne energije iz omrežja (Cetinkaya et

al., 2015 b). Skupaj z izgubami pa obstaja še dodaten problem, in sicer neprimerne tarifne

strukture. V Turčiji je v veljavi mehanizem izenačevanja (ang. equalization mechanism), kar

pomeni, da je končna tarifa enake za vse regije. Stroške regij posledično - z visokimi

izgubami - financirajo regije, ki imajo nizke izgube. Takšna politika je dolgoročno

nesprejemljiva, kljub temu da trenutno zadovoljuje podjetja, ki so veliko investirala v procesu

privatizacije (Cetinkaya et al., 2015a, str. 12). Spremembe pričakujejo v letu 2016, ko naj bi

bil mehanizem izenačevanja ukinjen.

9

Za neupravičene odjemalce so cene regulirane, medtem ko so cene za upravičene odjemalce

(tisti, ki imajo potrošnjo vsaj 4500 kWh na leto) svobodno izpogajane med kupcem in

prodajalcem (Atiyas et al., 2012, str. 26).

Cena električne energije pa je le sestavni del končne maloprodajne cene, ki jo plača potrošnik.

Cena električne energije torej predstavlja 57 % računa za električno energijo, 23 % gre za

dajatve za omrežje, preostalih 20 % pa so davki. Ti davki so: DDV, davek na porabo

električne energije in davek TRT – Radio in televizija (European Commission, 2014, str.

183).

V povprečju so turške maloprodajne cene tako za gospodinjstva kot tudi za industrijske

odjemalce malo pod povprečjem EU 28. V zadnjih treh letih pa lahko opazimo tudi upadanje

maloprodajnih cen v Turčiji. Za gospodinjske odjemalce so v letu 2012 cene padle z 0,11065

€/kWh na 0,09975 €/kWh. Za industrijske odjemalce pa so cene padle z 0,0876 €/kWh, na

0,07495 €/kWh (Eurostat – Energy price statistics, 2014).

Kljub napredkom na trgu električne energije v Turčiji čaka državo še kar nekaj dela in izzivov

v prihodnosti, da bi lahko zagotovila višji nivo konkurence na trgu in večjo transparentnost

oziroma zaupanje trgu. Komisija EU predvsem opozarja, da so potrebne izboljšave na

področju cen (neprimerne tarife), zaključek privatizacijskih postopkov, več transparentnosti in

seveda 100-odstotna odprtost trga (European Comission, 2014 b, str. 28).

10

APPENDIX B: List of abbreviations

Abbreviation Definition

ACER Agency for the Cooperation of Energy

Regulators

BOO Build – operate – own

BOT Build – operate – transfer

BOTAS Petroleum Pipeline Corporation

CEE region Central East European region

DSO Distribution system operator

EML Electricity Market Law

EMRA Energy Market Regulatory Authority

ENTSO-E European Network of Transmission System

Operators for Electricity

EPC European Price Coupling

EPIAS Energy Markets Operation Joint Stock Company

ERGEG European Regulators’ Group for Electricity and

Gas

ERI Electricity Regional Initiative

EU European Union

EUAS Electricity Generation Company

GDP Gross domestic product

IEM Internal energy market

MCP Market clearing price

MENR Ministry of Eenergy and Natural Resources

MFSC Market Financial Settlement Centre (tr. PMUM)

NLDC National Load Dispatch Centre (tr. MYTM)

NRA National Regulatory Authorities

nTPA / rTPA Negotiated third-party access / Regulated third-

party access

SEE region South East Europe region

SMP System marginal price

TEAS Turkish Electricity Generation Company (before

EUAS)

TEDAS Turkish Electricity Distribution Company

11

TEIAS Turkish Electricity Transmission Company

TEK Turkish Electricity Authority

TETAS Turkish Electricity Trading and Contracting

Company

TOR Transfer of operating rights

TPC Transition period contracts

TSO Transmission system operator

APPENDIX C: Table illustrating the Turkish electricity market and selected SEE

electricity markets (the Energy Community Contracting Parties)

Country Electricity generation / Gross

electricity consumed / Total

electricity customers

Installed capacity by energy sources in 2013

(%)

Turkey 240,154 GWh /

194,923 GWh /

66,505,050

Albania 5,956 GWh /

7,957 GWh /

1,161,626

Bosnia and

Herzegovina

16,303 GWh /

11,088 GWh /

1,492,215

Oil;

5.2

Hydro;

94.8

[CATEG

ORY

NAM…

[CATEG

ORY

NAM…

[CATEG

ORY

NAM…

[CATEG

ORY

NAM…

[CATEG

ORY

NAM…

[CATE

GORY

NAM…

[CATE

GORY

NAM…

[CATE

GORY

NAM…

12

Coal; 41

Gas; 15

Oil; 11

Hydro;

33

Renewabl

es 0

Former

Yugoslav

Republic of

Macedonia

5,676 GWh /

6,989 GWh /

682,356

Moldova 748 GWh /

3,551 GWh /

1,319,706

Montenegro 3,809 GWh /

3,323 GWh /

378,073

100; Hydro

Table continues

continued

Country Electricity generation / Gross

electricity consumed / Total

electricity customers

Installed capacity by energy sources in 2013

(%)

Serbia 37,537 GWh /

27,998 GWh /

3,580,579

Source: Electricity generation & transmission statistics of Turkey for year 2013, 2014; Energy Community

Secretariat, Annual Implementation Report 2013/2014, 2014.

[CATEG

ORY

NAM…

[CATEG

ORY

NAM…

[CATEG

ORY

NAM…

[CATEG

ORY

NAM… Gas; 5

Hydro;

40.2

Renewa

bles; 0.1

13

APPENDIX D: Table of feed in tariffs (for selected countries)

Country Feed-in-tariff wind Feed-in-tariff hydro Feed-in-tariff geothermal

Turkey On and offshore: approx. €ct 5.3 per kWh

Local-content bonus: approx. €ct 0.4-2.7 per kWh

Feed-in tariff: approx. €ct 5.6 per

kWh

Local-content bonus: approx. €ct

0.7-1.8 per kWh

Feed-in tariff: approx. €ct 8.1 per

kWh)

Local-content bonus: approx. €ct

0.5-2.1 per kWh

Denmark Onshore: €ct 4.95 – 8.90 per kWh (according to duration of payment) (§ 49 par. 1

EEG 2014) minus €ct 0.4 per kWh

Offshore: €ct 3.9 – 19.4 per kWh (according to duration of payment and scheme

chosen by plant operator) (§ 50 par. 1-3 EEG 2014) minus €ct 0.4 per kWh (§ 37

par. 3 no. 2 EEG 2014).

/ /

Greece NS=no support,

WS= with

support of

government

(fiscal,

financial,

subsidy)

Wind Interconnected systems Non-interconnected islands

€/MWh NS WS WS

up to 5 MW 105 85 90

> 5MW 105 82 90

Hydro NS WS

up to 1 MW 105 85

1 MW-5 MW 105 83

5 MW-15 MW 100 80

€/MWh NS WS

Low-

temperat

ure

(between

25°C -

90°C)

143 130

High-

temperat

ure

(above

90°C)

110 100

Hungary Wind power plants over 50 kVA can be connected to the grid only if there is a call

for tender. The tariff is set by the result of the tender.

Plants below 5 MW:

peak period: approx. € 0.12

valley period: approx. € 0.10

deep-valley period: approx. € 0.04

Plants of more than 5 MW

peak period: HUF 22.58 per kWh

(approx. € 0.07)

valley period: HUF 14.45 per kWh

(approx. € 0.05)

deep-valley period: HUF 14.45 per

kWh (approx. € 0.05)

Plants below 20 MW:

peak period: approx. € 0.12

valley period: approx. € 0.10

deep-valley period: approx. €

0.04

Plants between 20 and 50 MW:

peak period: approx. € 0.09

valley period: approx. € 0.08

deep-valley period: approx. €

0.03

14

Plants of more than 50 MW

peak period: approx. € 0.07

valley period: approx. € 0.05

deep-valley period: approx. €

0.05

Slovenia The uniform annual price is €ct 9.538 per kWh for all plant sizes Uniform annual price: €ct 9.261 –

10.547 per kWh, depending on the

capacity of the plant.

Uniform annual price: €ct 15.247

per kWh.

Great

Britain

Capacity GBP per kWh

≤ 1.5kW 0.16 (approx. 0.2 €/kWh)

1.5 kW - 15 kW 0.16 (approx. 0.2 €/kWh)

15kW - 100kW 0.16 (approx. 0.2 €/kWh)

100kW - 500kW 0.1334 (approx. 0.17 €/kWh)

500kW - 1.5MW 0.0724 (approx. 0.092 €/kWh)

> 1.5MW 0.0307 (approx. 0.039 €/kWh)

Capacity GBP per kWh

up to

15kW

0.1901 (approx. 0.2411

€/kWh)

15kW -

100kW

0.1775 (approx. 0.2252

€/kWh)

100kW -

500kW

0.1403 (approx. 0.1780

€/kWh)

500kW-

2MW

0.1096 (approx. 0.1390

€/kWh)

> 2MW 0.0299 (approx. 0.0379

€/kWh)

/

15

Source: Legal sources on renewable energy, 2015.

Portugal Indicative average rate for existing installations is € 74-75 per MWh. For existing traditional hydro

power plants (up to 10 MW), the

indicative average rate is € 91-95

per MWh.

For existing wave hydro power

plants (pilot-projects) up to 4 MW,

the indicative average rate is € 260

per MWh.

Plants (pre-commercial) up to

20MW: Indicative average rate: €

191 per MWh.

Commercial plants: Indicative

average rate: € 131 per MWh for

the first 100MW and € 101 per

MWh for the subsequent 150MW

For existing installations (i.e.

plants up to 3 MW), the

Indicative average rate is € 270

per MWh.

Croatia / For capacities below 5 MW:

≤ 300 kW: approx. €ct 13.9 per

kWh

> 300 kW and ≤ 2 MW: approx.

€ct 12.1 per kWh

> 2 MW: approx. €ct 11.4 per kWh

For capacities above 5 MW the

amount of the tariff depends on the

reference price

The tariff amounts to approx. €ct

15.6.

16

APPENDIX E: Transmission lines in Turkey

Source: Entose, 2014